Actuatable Plungers with Actuatable External Seals, and Systems and Methods Including the Same

ABSTRACT

A plunger apparatus, comprising: a plunger body able to travel within the tubular string; a flow channel through the plunger body; an actuatable external seal assembly operatively provided on or within an outer surface of the plunger body; and a plug mechanism mechanically integrated with the plunger body and reversibly moveable between a closed position and an open position with respect to the plunger body and flow channel, the open position configured to permit the passage of a continuous water slug past the plug mechanism and through the flow channel; and wherein the actuatable external seal assembly is actuated between the deployed position when the plug mechanism is operatively in the closed position and the retracted position when the plug mechanism is operatively in the open position.

CROSS REFERENCE TO RELATED APPLICATION

This application claims benefit of U.S. Provisional Application No. 62/271,714, filed Dec. 28, 2015, the entirety of each of which is incorporated by reference herein. This case is also related to U.S. Non-Provisional Application, Attorney Docket Number 2015EM427-A, filed concurrently herewith on Dec. 28, 2016.

FIELD OF THE DISCLOSURE

The presently disclosed invention relates generally to methods and systems for operating a plunger lift system. More particularly, this invention relates to a system, apparatus, and associated methods of unloading liquid in gas wells using a plunger lift system having improved hydrodynamics.

BACKGROUND

Gaseous hydrocarbon wells may produce and accumulate liquids within the wellbore conduit, resulting in a hydraulic backpressure upon the producing zone, resulting in a reduction in production rate. So long as the production rate and gas velocity up the wellbore are sufficient to carry the fluid with the gas, thereby keeping the wellbore “unloaded,” this accumulation is maintained at an equilibrium level and no artificial lift is required. However, when the liquid production rate exceeds the outflow capacity or rate of the produced gas, liquid buildup or “loading” is encountered, resulting in erratic, impeded, and eventually even ceased gas production will result. Artificial lift is required to remove produced, accumulated liquid that exceeds the capacity of the produced gas to remove, to sustain gas production from the well. This especially may be true late in the lifetime of the life of a gaseous hydrocarbon well (or even with a liquid-producing well also) and/or after the production rate of the wellbore fluid stream within the wellbore conduit decreases below a critical or threshold production rate.

“Plunger Lift” plungers are a form of artificial lift typically powered by reservoir gas pressure (and/or casing gas pressure) and may be utilized to remove the accumulated liquids from the wellbore conduit, thereby improving or increasing the production rate of the wellbore fluid stream from both the formation into the wellbore and from the wellbore to the surface. Historically, plungers either (1) continuously trip (travel) up and down (a “trip” is movement in one direction, while a “cycle” includes both up and down travel) within the wellbore conduit without periods of immobility; or (2) to selectively or intermittently trip or cycle within the wellbore conduit after brief periods of sustained immobility or rest (such as within a wellhead lubricator) at the surface and are released to fall back into the wellbore conduit responsive to surface measurements and controls.

While each of these approaches may be used to remove accumulated liquids from the wellbore conduit under certain conditions, each has distinct limitations. As illustrative, non-exclusive examples, a continuously cycled plunger may generate unnecessary wear of well components and/or constantly may restrict flow of the wellbore fluid stream there-past. As additional illustrative, non-exclusive examples, plungers that are housed within the well's lubricator may rely upon inaccurate surface measurements of well performance and/or may require that the gaseous hydrocarbon well be shut-in to permit the plunger to trip into the wellbore conduit to be used to remove liquids from the wellbore conduit. Rate of fall is another variable has advantages and disadvantages. Generally, more trips equates to more fluid removal from the wellbore, but more trips also may adversely result in more component wear, reliability, durability, and/or affect more production shut-in time.

“Casing” plungers operate under principles somewhat similar to “tubing” plungers, but often without the benefit of a tubing-casing annulus for gas/energy storage. Casing plungers also require some distinct adaptions for operating within a casing string as compared to tubing plungers. For example, to avoid casing wear and to adapt to the larger sealing surfaces, casing plungers typically use elastomer or other seals as opposed to metal seals which are more commonly used with tubing plungers, to avoid causing casing wear.

Another issue or limitation with some casing plungers is regulating the rise or fall speed. Rising velocity or velocity may be controlled by a choke orifice that relies on fluid to slow the device down. Unfortunately, this design has resulted in generally higher maintenance costs for casing plungers as compared to tubing plungers. That issue has also limited it's acceptance in the industry with the popular perception that casing plungers are mostly optimally fit for low production volume or “stripper” wells. Some plunger lift vendors are now beginning to market casing plungers for use in certain gas or hydrocarbon wells and are sometimes even recommending that a tubing string is not installed after completion.

On the advantage side though, casing plungers may be better suited for certain production applications than tubing plungers for some wellbore fluid production installations due to the basic physics of fluid displacement using a “larger piston” than tubing plungers (See FIG. 1-2). The larger diameter may afford a casing plunger more lifting power with the same differential pressure, than is available for a tubing plunger.

This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present technology. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present technology. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.

Gas production from hydrocarbon reservoirs is often associated with liquid production. The produced liquids may be reservoir formation water or condensed hydrocarbon gas. During the early life of a gas well, the gas production rate is sufficient to carry produced liquid to the surface. As the reservoir pressure is depleted with continuous production, the gas production rate will eventually decrease to a point where the produced liquids can no longer be carried by gas flow out of the wellbore. As a result, the produced liquid starts to accumulate at the bottom of the well, which is called liquid loading.

Liquid loading is a common and challenging problem in gas well operations, particularly in the later life of wells. Removal of liquid, in many instances water, out of the gas well becomes important to maintain gas production and keep the well flowing. This can be accomplished by various kinds of artificial lift methods and systems. Plunger lift methods and systems are generally considered the most cost effective artificial lift approaches in the industry today.

Many conventional plunger lift systems consist of a plunger, well production tubing, a bottom hole assembly that includes tubing stopper and bumper spring, and wellhead equipment that includes plunger catcher, lubricator, flow outlet, valves, and control device. The plunger is a cylindrical device used in the tubing and it is designed to seal against the interior of the tubing while it moves freely inside the tubing string. In a typical plunger lift operation, the well is shut-in so that the plunger can descend to the bottom of the well below the accumulated continuous liquid column; after sufficient wellbore pressure has built up, the well valve is opened; the wellbore pressure pushes the plunger and, consequently, the column of liquid on top of plunger up the well all the way to surface; when reaching the surface, the plunger is held at the wellhead to allow the gas to flow for as long as the well permits; then the plunger is released into the well again for a new cycle of plunger lift operation.

The well shut-in requirement during plunger descent is one of the major disadvantages for conventional plunger lift technology. This limitation restricts the use of the technology for high rate wells because of the unaffordable production loss. Because of the hourly, periodic wellbore operation switches, a wellhead surface control system, usually comprising an electronic control panel, a power supply (for remote wells, a solar panel is very common), and pneumatic flow-control valves, becomes essential.

Continuous flow plungers such as those described in U.S. Pat. No. 6,209,637, U.S. Pat. No. 6,644,399, and U.S. Pat. No. 7,243,730 attempt to address the well shut-in time problem. However, each of the devices and methods disclosed in these patents requires a surface control device. Surface control devices keep the cost high for plunger operations. While providing flexibility or options for optimizing plunger lift operations, the surface control system typically accounts for more than 80% of the total capital expense of a plunger lift system installation. In addition, none of the current plungers are applicable in high rate gas producing wells and none of them appear to utilize improved hydrodynamics.

Field experiences have shown that continuous flow plungers have difficulty reaching the tubing bottom in high flow rate wells. This may be due to a lack of sufficient mass, an inability to overcome hydrodynamic forces such as pressure and drag caused by continuous water, or another design limitation.

What is needed are more efficient and effective plunger lift systems and methods for artificially lifting liquids out of gas wells that can operate with or without surface control equipment and operate in high rate gas producing wells. The plunger lift industry remains in need of more effective, longer-lasting, and longer-lasting-sealing mechanisms than is currently known in the casing plunger art. Need exists for improvements in casing plunger reliability and operational flexibility and for application expansion and enhancements. The art today also needs improved selectively-actuated plungers and for systems and methods that include selectively actuated plungers.

SUMMARY

One exemplary embodiment of the present invention discloses a plunger apparatus, comprising: a plunger body having a substantially annular cross-section and an outer diameter, wherein the outer diameter is less than an inner diameter of a tubular string of a gas producing well, the plunger body able to travel within the tubular string; a flow channel through the plunger body; an actuatable external seal assembly operatively provided on or within an outer surface of the plunger body, the actuatable external seal assembly having a deployed position and a retracted position; and a plug mechanism mechanically integrated with the plunger body and reversibly moveable between a closed position and an open position with respect to the plunger body and flow channel, the open position configured to permit the passage of a continuous water slug past the plug mechanism and through the flow channel; wherein the plug mechanism operatively extends from an end of the plunger apparatus and comprises a substantially streamlined profile when the plug mechanism is operatively extended in the open position with respect to the plunger body and flow channel; and wherein the actuatable external seal assembly is actuated by the plug mechanism between the deployed position when the plug mechanism is operatively in the closed position and the retracted position when the plug mechanism is operatively in the open position.

In another exemplary embodiment, the plunger apparatus is configured to fall through the fluid in the wellbore tubular when the plug mechanism is in the open position and the actuatable seal assembly is in the retracted position at a falling velocity relative to the continuous water slug velocity greater than about (150+50×M) feet per minute (ft/min), where M is the mass in units of lbm of the plunger apparatus.

Another exemplary embodiment of the presently disclosed technology includes a method of producing hydrocarbon-containing gas, comprising: providing a hydrocarbon well having a wellbore, a flow line in fluid communication with the wellbore, a top portion with a tubular head stopper, and a bottom portion with a bottom bumper stopper; producing a volume of liquids and a gaseous stream imparting a gaseous pressure from the bottom portion to the top portion of the wellbore, wherein at least a portion of the produced volume of liquids remains in the bottom portion of the wellbore; and operating a plunger apparatus in the wellbore in a plunger lift cycle, the lift cycle comprising: lifting at least a portion of the produced volume of liquids in the bottom portion of the wellbore towards the top portion of the wellbore and within the flow line utilizing the gaseous pressure from the bottom portion to the top portion of the wellbore, wherein the plug mechanism of the plunger apparatus comprises; a plunger body having a substantially annular cross-section and an outer diameter, wherein the outer diameter is less than an inner diameter of a tubular string of a gas producing well, the plunger body able to travel within the tubular string; a flow channel through the plunger body; an actuatable external seal assembly operatively provided on or within an outer surface of the plunger body, the actuatable external seal assembly having a deployed position and a retracted position; and a plug mechanism mechanically integrated with the plunger body and reversibly moveable between a closed position and an open position with respect to the plunger body and flow channel, the open position configured to permit the passage of a continuous water slug past the plug mechanism and through the flow channel; wherein the plug mechanism operatively extends from an end of the plunger body and comprises a substantially streamlined profile when the plug mechanism is operatively extended in the open position with respect to the plunger body and flow channel; and wherein the actuatable external seal assembly is actuated by the plug mechanism between the deployed position when the plug mechanism is operatively in the closed position and the retracted position when the plug mechanism is operatively in the open position; the method further comprising impacting the tubular head stopper with the plunger apparatus causing the plunger apparatus to change the operating state from the closed position to an open position with respect to the plunger body and flow channel, and causing the actuatable external seal assembly to operatively change from the deployed position to the retracted position; descending the automatic plunger apparatus in the open position to the bottom of the wellbore, wherein a gravitational force on the plunger apparatus is greater than a combined drag force and pressure force on the plunger apparatus caused by the passage of the volume of fluids and the gaseous stream; impacting the bottom bumper stopper with the plunger apparatus causing the plunger apparatus to automatically change the operating state from the open position to the closed position and actuate the external seal assembly from the retracted position to the deployed position, and repeating the plunger lift cycle.

Yet another embodiment may include an automatic plunger apparatus comprising: a plunger body having a first end, a second end, a substantially annular cross-section configured to form a flow channel through the plunger body from the first end to the second end, the plunger body able to travel within a tubular string; and a plug mechanism configured to operatively move between a closed position configured to obstruct the flow of fluids through the flow channel and an open position configured to permit the flow of fluids through a flow channel; wherein the plunger apparatus is configured to travel in the general direction of a gravitational force (“fall”) in the open position until the plunger apparatus engages a first actuation force causing the plug mechanism to automatically move to the closed position.

BRIEF DESCRIPTION OF THE DRAWINGS

The foregoing and other advantages of the present techniques may become apparent upon reviewing the following detailed description and drawings in which:

FIGS. 1A-1D show longitudinal-cut, cross-sectional views of four exemplary one-piece plunger apparatuses, including the internal locking mechanisms of the plungers.

FIGS. 1E-1F show illustrative external views of the exemplary one-piece plunger apparatus of FIGS. 1A-1D.

FIGS. 2A-2D illustrate a series of schematics showing a single cycle of the automatic plunger lift process utilizing the plunger of any one of FIGS. 1A-1E.

FIGS. 3A-3B illustrate the stages of the automatic plunger of FIGS. 1A-1E being closed by the impact at the subsurface bumper spring of FIGS. 2B and 2C.

FIGS. 4A-4B illustrate the stages of the plungers of FIGS. 1A-1E being closed by the impact at the wellhead assembly of FIGS. 2A and 2D.

FIG. 5 illustrates a method of operating the plunger of FIGS. 1A-1E.

FIG. 6 illustrates a method of manufacturing the plunger of FIGS. 1A-1E.

FIGS. 7-8 illustrate exemplary embodiments including a controller mechanism and a plug-type valve system.

FIGS. 9-10 illustrate exemplary embodiments including a controller mechanism and an internal valve mechanism.

FIG. 11 is a schematic cross-sectional view of illustrative, non-exclusive examples of a hydrocarbon well that may include and/or utilize a plunger according to the present disclosure.

FIG. 12 is a flowchart depicting methods according to the present disclosure of removing a liquid from a wellbore conduit of a gaseous hydrocarbon well with a plunger.

FIG. 13 is a schematic view of an illustrative, non-exclusive example of a portion of a process flow that may be utilized with a plunger according to the present disclosure.

FIGS. 13-18 are schematic views of an illustrative, non-exclusive example of another portion of the process flow.

FIG. 19 is a schematic representation of illustrative, non-exclusive examples of a plunger according to the present disclosure in a low fluid drag state and located within a wellbore conduit.

FIG. 20 is a schematic representation of illustrative, non-exclusive examples of a plunger according to the present disclosure in a high fluid drag state and located within a wellbore conduit.

FIG. 21 is a schematic representation of an illustrative, non-exclusive example of a drag-regulating structure according to the present disclosure in a low fluid drag state.

FIG. 22 is a schematic representation of an illustrative, non-exclusive example of the drag-regulating structure of FIG. 21 in a high fluid drag state.

FIG. 23 is a schematic representation of an illustrative, non-exclusive example of a drag-regulating structure according to the present disclosure in a low fluid drag state.

FIG. 24 is a schematic representation of an illustrative, non-exclusive example of the drag-regulating structure of FIG. 23 in a high fluid drag state.

FIG. 25 is a schematic representation of an illustrative, non-exclusive example of a drag-regulating structure according to the present disclosure in a low fluid drag state.

FIG. 26 is a schematic representation of an illustrative, non-exclusive example of the drag-regulating structure of FIG. 25 in a high fluid drag state.

FIG. 27 is a schematic side view of illustrative, non-exclusive examples of a plunger according to the present disclosure in a low fluid drag state and located within a wellbore conduit.

FIG. 28 is a schematic top view of the plunger of FIG. 27.

FIG. 29 is a schematic side view of illustrative, non-exclusive examples of a plunger according to the present disclosure in a high fluid drag state and located within a wellbore conduit.

FIG. 30 is a schematic top view of the plunger of FIG. 29.

DETAILED DESCRIPTION AND BEST MODE OF THE DISCLOSURE

In the following detailed description section, specific embodiments of the present invention are described in connection with preferred embodiments. However, to the extent that the following description is specific to a particular embodiment or a particular use of the present invention, this is intended to be for exemplary purposes only and simply provides a description of the exemplary embodiments. Accordingly, the invention is not limited to the specific embodiments described below, but rather, it includes all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.

Definitions

Various terms as used herein are defined below. To the extent a term used in a claim is not defined below, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent.

The terms “a” and “an,” as used herein, mean one or more when applied to any feature in embodiments of the present inventions described in the specification and claims. The use of “a” and “an” does not limit the meaning to a single feature unless such a limit is specifically stated.

The term “about” is intended to allow some leeway in mathematical exactness to account for tolerances that are acceptable in the trade. Accordingly, any deviations upward or downward from the value modified by the term “about” in the range of 1% to 10% or less should be considered to be explicitly within the scope of the stated value.

In the claims, as well as in the specification above, all transitional phrases such as “comprising,” “including,” “carrying,” “having,” “containing,” “involving,” “holding,” “composed of,” and the like are to be understood to be open-ended, i.e., to mean including but not limited to. Only the transitional phrases “consisting of” and “consisting essentially of” shall be closed or semi-closed transitional phrases, respectively, as set forth in the United States Patent Office Manual of Patent Examining Procedures, Section 2111.03.

The term “continuous water” or “water slug” refers to a volume of water encountered in a well sufficient to impart at least a “liquid load” on a plunger falling through the well. Note that the water will generally be water produced from a subterranean formation and may include some production fluids, drilling fluids, gases, and other materials that a person of ordinary skill in the art would expect to find in a well.

The term “exemplary” is used exclusively herein to mean “serving as an example, instance, or illustration.” Any embodiment described herein as “exemplary” is not necessarily to be construed as preferred or advantageous over other embodiments.

The terms “preferred” and “preferably” refer to embodiments of the inventions that afford certain benefits under certain circumstances. However, other embodiments may also be preferred, under the same or other circumstances. Furthermore, the recitation of one or more preferred embodiments does not imply that other embodiments are not useful, and is not intended to exclude other embodiments from the scope of the inventions.

The term “releasably connected,” as used herein, means two parts or physical elements that are capable of a connected mode of operation and a disconnected or separate mode of operation. In the connected mode, the two parts or elements are sufficiently connected to operate as a single physical element. The two parts or elements are releasable in that they can be released from each other or disconnected without damaging either of the two elements such that they can be reconnected without having to be remanufactured in any way. Examples of releasable connections include clips, magnetic attachments, threaded attachments, pressure connections, spring-loaded connections, and the like. Examples of “permanent connections” that would not be considered “releasable” include welded connections, bolted connections, and the like.

The term “streamlined profile,” as used herein, means a shape that is longest in the direction of travel and tapered on both ends such as to promote streamlined flow of fluids around the profile or shape and specifically excludes substantially spheroid shapes.

The terms “substantial” or “substantially,” as used herein, mean a relative amount of a material or characteristic that is sufficient to provide the intended effect. The exact degree of deviation allowable may in some cases depend on the specific context.

The definite article “the” preceding singular or plural nouns or noun phrases denotes a particular specified feature or particular specified features and may have a singular or plural connotation depending upon the context in which it is used.

The term “continuous water” or “water slug” refers to a volume of water encountered in a well sufficient to impart at least a “liquid load” on a plunger falling through the well. Note that the water will generally be water produced from a subterranean formation and may include some production fluids, drilling fluids, gases, and other materials that a person of ordinary skill in the art would expect to find in a well.

The term “exemplary” is used exclusively herein to mean “serving as an example, instance, or illustration.” Any embodiment described herein as “exemplary” is not necessarily to be construed as preferred or advantageous over other embodiments.

The terms “preferred” and “preferably” refer to embodiments of the inventions that afford certain benefits under certain circumstances. However, other embodiments may also be preferred, under the same or other circumstances. Furthermore, the recitation of one or more preferred embodiments does not imply that other embodiments are not useful, and is not intended to exclude other embodiments from the scope of the inventions.

The term “releasably connected,” as used herein, means two parts or physical elements that are capable of a connected mode of operation and a disconnected or separate mode of operation. In the connected mode, the two parts or elements are sufficiently connected to operate as a single physical element. The two parts or elements are releasable in that they can be released from each other or disconnected without damaging either of the two elements such that they can be reconnected without having to be remanufactured in any way.

Examples of releasable connections include clips, magnetic attachments, threaded attachments, pressure connections, spring-loaded connections, and the like. Examples of “permanent connections” that would not be considered “releasable” include welded connections, bolted connections, and the like.

The term “streamlined profile,” as used herein, means a shape that is longest in the direction of travel and tapered on both ends such as to promote streamlined flow of fluids around the profile or shape and specifically excludes substantially spheroid shapes.

The terms “substantial” or “substantially,” as used herein, mean a relative amount of a material or characteristic that is sufficient to provide the intended effect. The exact degree of deviation allowable may in some cases depend on the specific context.

The definite article “the” preceding singular or plural nouns or noun phrases denotes a particular specified feature or particular specified features and may have a singular or plural connotation depending upon the context in which it is used.

In the present disclosure, several of the illustrative, non-exclusive examples have been discussed and/or presented in the context of flow diagrams, or flow charts, in which the methods are shown and described as a series of blocks, or steps. Unless specifically set forth in the accompanying description, it is within the scope of the present disclosure that the order of the blocks may vary from the illustrated order in the flow diagram, including with two or more of the blocks (or steps) occurring in a different order and/or concurrently. It is also within the scope of the present disclosure that the blocks, or steps, may be implemented as logic, which also may be described as implementing the blocks, or steps, as logics. In some applications, the blocks, or steps, may represent expressions and/or actions to be performed by functionally equivalent circuits or other logic devices. The illustrated blocks may, but are not required to, represent executable instructions that cause a computer, processor, and/or other logic device to respond, to perform an action, to change states, to generate an output or display, and/or to make decisions.

As used herein, the term “and/or” placed between a first entity and a second entity means one of (1) the first entity, (2) the second entity, and (3) the first entity and the second entity. Multiple entities listed with “and/or” should be construed in the same manner, i.e., “one or more” of the entities so conjoined. Other entities may optionally be present other than the entities specifically identified by the “and/or” clause, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, a reference to “A and/or B,” when used in conjunction with open-ended language such as “comprising” may refer, in one embodiment, to A only (optionally including entities other than B); in another embodiment, to B only (optionally including entities other than A); in yet another embodiment, to both A and B (optionally including other entities). These entities may refer to elements, actions, structures, steps, operations, values, and the like.

As used herein, the phrase “at least one,” in reference to a list of one or more entities should be understood to mean at least one entity selected from any one or more of the entity in the list of entities, but not necessarily including at least one of each and every entity specifically listed within the list of entities and not excluding any combinations of entities in the list of entities. This definition also allows that entities may optionally be present other than the entities specifically identified within the list of entities to which the phrase “at least one” refers, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, “at least one of A and B” (or, equivalently, “at least one of A or B,” or, equivalently “at least one of A and/or B”) may refer, in one embodiment, to at least one, optionally including more than one, A, with no B present (and optionally including entities other than B); in another embodiment, to at least one, optionally including more than one, B, with no A present (and optionally including entities other than A); in yet another embodiment, to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other entities). In other words, the phrases “at least one,” “one or more,” and “and/or” are open-ended expressions that are both conjunctive and disjunctive in operation. For example, each of the expressions “at least one of A, B and C,” “at least one of A, B, or C,” “one or more of A, B, and C,” “one or more of A, B, or C” and “A, B, and/or C” may mean A alone, B alone, C alone, A and B together, A and C together, B and C together, A, B and C together, and optionally any of the above in combination with at least one other entity.

In the event that any patents, patent applications, or other references are incorporated by reference herein and (1) define a term in a manner that is inconsistent with and/or (2) are otherwise inconsistent with, either the non-incorporated portion of the present disclosure or any of the other incorporated references, the non-incorporated portion of the present disclosure shall control, and the term or incorporated disclosure therein shall only control with respect to the reference in which the term is defined and/or the incorporated disclosure was present originally.

As used herein the terms “adapted” and “configured” mean that the element, component, or other subject matter is designed and/or intended to perform a given function. Thus, the use of the terms “adapted” and “configured” should not be construed to mean that a given element, component, or other subject matter is simply “capable of” performing a given function but that the element, component, and/or other subject matter is specifically selected, created, implemented, utilized, programmed, and/or designed for the purpose of performing the function. It is also within the scope of the present disclosure that elements, components, and/or other recited subject matter that is recited as being adapted to perform a particular function may additionally or alternatively be described as being configured to perform that function, and vice versa.

Embodiments of the disclosed plunger technology may comprise a cylindrical tubular body that possesses sealing means at its outer perimeter surface, the sealing means being selectively expandable into a deployed position during a liquid lifting or ascending traverse of the wellbore and retractable to a retracted position during a falling or descending, non-lifting traverse of the wellbore. The disclosed plunger may also include a valve element used to open, close, or regulate fluid flow through the internal throughbore or flow path of the plunger body. The valve may comprise a plug mechanism, such as illustrated in FIGS. 1A-4B, or a positionable valve element, such as illustrated in FIGS. 21-30. It is understood that for purposes herein that reference to a valve or plug is not intended to exclude the other. References to either a valve mechanism or plug mechanism may be applied broadly in principle to any plunger throughbore flow regulating mechanism and is not intended to exclude any other types of fluid flow mechanisms. Term usage herein is merely referring to the illustrated exemplary embodiments and arbitrarily using terminology most readily applicable to a then-referenced embodiment. It is understood that valves and plugs are generally referring to flow control mechanisms that may be functionally interchangeable according to desired application.

The presently disclosed combination of the selectively actuatable external seal(s) and the throughbore valve element each create a continuous interface between the liquid load above the plunger and pressured gas below the plunger when the plunger ascends in the wellbore. During descending, the plug or valve is in the open position and the external seals are in the retracted or nested position within or against the plunger body.

The disclosed plunger may also include a locking mechanism that prevents accidental engagement or actuation of either the valve member or actuatable seals, outside of the selected window of operational design parameters. Exemplary locking mechanisms are presented herein, illustrating various mechanical concepts that may be utilized for such purposes.

The cylindrical tubular body of any of the disclosed plungers is adapted to travel within wellbore such as casing strings and/or production tubing strings of gas producing wells, including such wells that produce both gas and liquid. The disclosed plunger system is typically utilized to remove liquid accumulated within the wellbore that is undesirably creating hydrostatic backpressure upon the producing formation. The cylindrical tubular body of any of the disclosed plungers is also adapted to travel within pipeline tubular strings.

The cylindrical tubular body of any of the disclosed plungers may be of any size suitable for travel within the wellbore tubular strings designated for lifting the liquid. The presently disclosed plunger apparatus and method are particularly suited for use as what is commonly known within the artificial lift industry as a “casing plunger,” although the presently disclosed technology may certainly be utilized in tubulars designated as “production tubing.” One of the drawbacks of using a casing string as the production string is concern for casing wear due to repetitive seal contact from plunger seals as the plunger traverses the tubular in both directions. However, one of the desirable benefits for using a casing string as the production string is the larger diameter creates a larger cross-sectional flow area and reduced friction drop and increase flowing capacity. The presently disclosed technology provides a long-needed solution for utilizing a casing string as the wellbore production string, while reducing wear concerns by only deploying the external seals during the lifting upstroke traverse of the plunger within the wellbore.

For example, the present plungers may be installed in tubing strings having inner diameters ranging between about 1 inch and about 6 inches. Common production tubulars range between about 1.05 inches and about 4.5 inches and having corresponding inner diameters somewhat smaller than these outer dimensions, with tubulars being sized at virtually any incremental size within those ranges, such as 2⅜ inches, 2⅞ inches, 3½ inches, 4½ inches, etc. The presently disclosed plungers may be deployed in casing strings ranging, for example, from 3½ inches to 15 inches. Utilization of the presently disclosed technology may also be applicable to yet larger tubulars, such as may be used for either casing strings, or even for pipeline, such as for use in pigging or other pipeline servicing operations. The cylindrical tubular body of any of the disclosed plungers also may be of any size suitable for travel within any of the wellbore production casing strings in which the plunger may be utilized, including but not limited to production casings in a range of from 3½ to 15 inches. The plungers, apparatus, methods, and systems provided herein may also be useful in non-wellbore tubular operations for conveying gasses that may experience periodic liquid accumulation, such as but not limited to gaseous pipeline operations. Pipeline sizes may commonly be significantly larger than the commonly used casing sizes. It is understood that for brevity, the term “wellbore” should be interpreted broadly to encompass other such tubular operations. While the sizes are expressed here in inches, it should be understood that corresponding metric dimensions may be used and denominated depending on the application.

Regardless of the inner diameter size of the tubular string in which the plunger travels, the tubular plunger body is configured to provide a substantially annular cross-section and to have an outer diameter sized to fit the tubular strings. For example, the outer diameter of the plunger body may be less than the inner diameter of the tubular string. As will be understood, the outer diameter of the plunger body should be less than the inner diameter of the tubular string to reduce the contact friction forces between the plunger body and the tubular string. Exemplary clearances between the plunger body outer diameter and the tubular string inner diameter may be within the range from about 1.0 inch such as in larger tubular applications, such as with a casing plunger application, to about 0.001 inches in a production tubing application. In an exemplary implementation having 2-3/8 inch tubing with 1.995 inch nominal inner diameter and a drift inner diameter of 1.901 inches, a recommended plunger body outer diameter may be between about 1.89 inches and about 1.90 inches. In some implementations, the outer diameter of the plunger body may be less than the inner diameter of the tubular string, wherein less is limited only by the manufacturing tolerances of the components where the outer diameter is sized to prevent binding. Additionally or alternatively, the outer diameter may be selected based at least in part on fluid dynamics considerations, such as described further below. In such implementations, the outer diameter and the configuration of the outer surface of the plunger body may be suitably engineered to create the desired flow properties.

Embodiments of the disclosed plunger lift systems include “one-piece” (“integrated”) plunger configurations as well as “two-piece” configurations. The one-piece configurations include a plug mechanism physically integrated with the plunger body and having a closed position and an open position. In a one-piece configuration, the plug or valve mechanism travels with the plunger body during traversal of the wellbore in both directions. The open position of the plug is configured to permit the passage of continuous water (or water slug) past the exterior of the plug mechanism due to retraction of the actuatable external seal, and the open setting of the plug or valve mechanism within the plunger throughbore or flow channel of the plunger body. In some embodiments, the plug mechanism may extend from the plunger apparatus in a direction of travel and comprises a substantially streamlined profile.

The “two-piece” embodiments include a plunger body and a plug mechanism releasably connected to the plunger body and having a closed (connected) position and an open (released) position, such that in the released position, the plunger is separated into the two pieces. The open position is configured to permit the passage of continuous water through the throughbore flow channel while maintaining the open position, and passage of continuous water past the retracted external seal assembly, wherein the plug mechanism comprises a substantially streamlined profile.

Some embodiments of the disclosure include a two-stage locking mechanism. The function of the locking mechanism is to ensure that the selectable or actuatable internal valve element and/or external seal assembly remains in the desired position during plunger operations. The locking mechanism prevents the valve element and seal assembly from undesirably engaging or deploying when the plunger splashes into the accumulated wellbore liquid or water slug at a high descending velocity. On the other hand, the locking mechanism can be unlocked by an actuation force when the plunger reaches the subsurface bumper spring at the bottom of the well configured to engage the locking mechanism. Locking and actuation mechanisms may be engineered as needed or desired to accommodate the plunger technology being utilized. External seal assembly and internal valve (or plug) assembly interaction and actuation mechanisms may utilize or include generally any combination of mechanical, hydraulic, electric, and combinations thereof functional means. Numerous wellbore tools and components have been designed and utilized over the years that include deployable and retractable mechanisms. However, the presently disclosed technology of utilizing actuatable or selectively deployable and retractable external seal assemblies on wellbore plungers is lacking and needed in the plunger lift industry.

In plunger lift applications, the associated wellhead assembly of the system typically has two primary functions. The first is to actuate the plunger from a closed position to an open position when the plunger comes to the wellhead so that the plunger can fall back against fluid flows. The second is to absorb the impact from a plunger traveling at a high velocity to prevent potential equipment damage.

The application of the presently disclosed technology is not only limited to subsurface operation. Since control devices are not required, the system can be installed in the subsurface wellbore, which adds significant flexibility and makes different wellbore equipment configurations available.

One particular advantage of the present disclosure is to provide plunger lift systems that are applicable in high rate (e.g. over about 200 kscf/d) gas wells and capable of unloading more water than conventional, existing plunger lift systems. At the same time, embodiments of the plunger lift system are able to lift produced liquid to the surface while automatically cycling in a well. The capability of avoiding shutting-in the well and improving liquid unloading capacity make embodiments of this invention effective and economic field tools or devices for unloading liquid from gas wells.

Some of the advantages of the presently disclosed methods and apparatuses include: 1) The system can work automatically without the assistance of control equipment; 2) The plunger lift system can be installed or run subsurface in gas wells; 3) Expanded application range of plunger lift system to high rate gas wells; 4) Can be used in conjunction with control devices in order to optimize plunger operations; and 5) Permits use of multiple multi-stage automatic plungers.

In general, a plunger surrounded by flowing fluids is subject to four primary forces: gravity force, fluid drag force, pressure force, and friction force due to contact with tubular. The gravity force is always pointing downwards to the earth while the directions of the drag and pressure forces are the same as the direction of flow of fluids relative to the plunger, while the contact force acts opposite to the direction of travel of the plunger. In a producing well with a falling plunger, the drag, pressure, and contact forces are pointing upwards, i.e. against gravity. The magnitude difference between gravity force and drag, pressure, and contact forces determines whether the plunger descends, ascends, or remains suspended in the wellbore. When the gravity force is greater than the combined drag force, pressure force, and contact force, the plunger falls in the wellbore. Otherwise, the plunger will suspend or move upwards with the flowing fluids. The greater the difference is, the faster the plunger falls (e.g. the greater the plunger's “falling velocity”).

Improving the plunger falling velocity may be achieved by any one of the following strategies: 1) increasing the weight of plunger so as to increase gravity force; 2) mitigating the pressure force on the plunger by reducing restriction to flow, e.g. the effective cross-sectional area (normal to the flow) of the plunger; 3) mitigating the drag force on the plunger by streamlining the profile of the plunger; and 4) reducing the frictional force due to contact between the plunger and the tubular. In the following exemplary embodiments of the disclosure, some combination of these strategies will be used.

The presently disclosed technology facilitates the ability to utilize improved plunger descending travel velocity due to improved fluid passage within the plunger through-bore and valve or plug. However, the presently disclosed technology still further improves plunger descending travel velocity by facilitating improved fluid passage external to the plunger boy, by retracting the external seals into a retracted position. Selective actuation of the external seal assembly may facilitate reduced external fluid drag past the plunger body as the plunder falls within the wellbore tubular. Still further velocity improvements and control may be achieved through use of “smart” technology in combination with the actuatable external seals and controllable internal valve assemblies. The addition of smart technology to the plunger may still further facilitate the ability to utilize both or either of the internal valve assembly and actuatable external seal assembly to regulate the velocity of the plunger within the wellbore, even more particularly to regulate plunger velocities at different locations within the wellbore, as desirably selected.

In one exemplary embodiment, the disclosed plunger may be a one-piece plunger utilizing an axially movable plug as the internal valve member and an actuatable external seal assembly provided on or within an outer surface of the plunger body. The actuatable external seal assembly may be actuatable operate between a deployed position and a retracted position. The position of the external seal assembly may be directly responsive to and actuated in conjunction with the position of the plug as the plug operates between a closed position and open position.

FIGS. 1-30 provide illustrative, non-exclusive examples of plungers 50 according to the present disclosure, of components of plungers 50, and/or of methods and/or process flows that may include and/or utilize plungers 50. Elements that serve a similar or at least substantially similar purpose are labeled with like numbers in each of FIGS. 1-30 and these elements may not be discussed in detail herein with reference to each of FIGS. 1-30. Similarly, all elements may not be labeled in each of FIGS. 1-30, but reference numerals associated therewith may be utilized herein for consistency. Elements, components, and/or features that are discussed herein with reference to one or more of FIGS. 1-30 may be included in and/or utilized with any of FIGS. 1-30 without departing from the scope of the present disclosure.

Exemplary FIGS. 1A-1D illustrate simplified, longitudinal-cut, cross-sectional views of four exemplary one-piece plunger apparatuses, including the internal locking mechanisms of the plungers. FIG. 1D shows an exemplary embodiment of a plunger configuration having an internal venturi profile and a one-stage locking mechanism. FIG. 1A shows a longitudinal-cut, cross-sectional view of an exemplary one-piece plunger apparatus. View 400 shows a plunger 402 in the closed configuration and view 420 shows the plunger 402 in the open configuration. View 400 also illustrates actuatable external seals 430 in the deployed position, such as used during the uphole, lifting traverse. View 420 illustrates actuatable external seals 430 in the retracted position. View 420 also illustrates a plurality of selectively deployable and retractable seals 430. The plunger 402 includes a cylindrical body 403, a center cylinder 404, a plug (and stem) mechanism 406, an actuation member 407 having a first end 408 and a second end 410, and a locking apparatus having balls 416 a to engage the body of the actuation member, grooves 416 b to engage the balls, and a spring and ball arrangement 416 c to engage the actuation member 407 near the second end 410.

Views 400 and 420 also illustrates one simplified example of a mechanical force actuation mechanism used to actuate the seal assembly between the retracted position and the expanded or deployed position. In this simple example, mandrel 450 may be positioned within an interior or throughbore of the plunger body, such that and end 452 of the mandrel 450 may engage a surface 414 of the plug 406. The mandrel 450 may reciprocate between the seal deployed position and seal retraction position such as within a groove or surface 440 in the plunger body. If desired, a spring or other biasing force may be utilized to position the mandrel in the position whereby the seals are retracted and disengaged. In some embodiments, mandrel 450 may be engaged with plug 406 such that no separate biasing element is needed. A biasing force or may be created by engagement of the seal actuation member, mandrel 450, with the plunger may ensure the seal deployment happens in conjunction with closure of plug 406. Biasing mandrel 450 may also act to safely prevent inadvertent activation of the seals into the deployed position while the plunger is falling in the downhole traversing mode. It is understood that seals 430 are illustrated as typical ring type seals. The seals 430 may be actuatable between expanded and retracted by mechanical, fluid, hydraulic, etc., forces, such as by elastic distortion or inflation, or by mechanical movement. Mechanical movement mechanisms may include sliding sleeves, sliding mandrels, uncoiling an overlapping seal, and combinations thereof Multiple mandrels may be utilized to achieve a desired direction of expansion force on the perimeter of the plunger body. FIGS. 7-10 illustrate simplified embodiments of a plunger assembly having a selectively inflatable / deflatable seal assembly.

It is noted that due to the numerous engineering possibilities for providing external seal mechanisms on plunger bodies, only some of the exemplary seal embodiments are illustrated in the Figures, such as FIG. 1A and FIGS. 7-10. External seals as illustrated in any of these Figures could also be adapted for use in the other Figures provided herewith.

View 420 of FIG. 1A additionally illustrates a throughbore opening creating flow channel 415, a plurality of turbulent sealers 418 that are also included on seals 430 in order to create a mix of vortices between the exterior surface of the actuatable seal and the wellbore conduit wall. A fishing neck 419 is also provided. In one illustrative embodiment, the plunger 402 includes a plug mechanism 406 (or plug-type valve element) including an elliptical or streamlined ball on a rod stem. The plug mechanism 406 is configured to cyclically close and open the flow channel 415 during operation. When the plug mechanism 406 closes, the interior of a well conduit (tubular) is sealed so that the liquid in the well above the plunger 402 is prevented from falling through the plunger 402 during ascent. In this manner, liquid can be lifted to the surface by the means of the gas pressure build-up in a well. When the plug mechanism 406 opens the plunger 402 can easily fall through the wellbore fluid (be it gas, water, other liquids, or combinations) down to the bottom of the well.

Beneficially, the shape of the plug mechanism 406 and the inside profile of the plunger cylinder 403 are configured to mitigate the effects of hydrodynamic drag forces (“fluid-dynamically optimized”) generated by the internal flow as the plunger 402 falls against high rate upwards gas and/or liquid flows. The shape of each element of the plunger 402, including, but not limited to, the plug or valve 406, the valve stem housing 405, and the plunger body 403 are carefully designed to reduce or mitigate such flow friction and to enhance the descending velocity of the plunger 402 against high rate fluid flows, while maintaining other plunger functionality such as sealing the produced gases from the water, repeatability of operation, and resistance to mechanical failure, as discussed above. As such, the plunger 402 can descend at an acceptable velocity even against high rate gas and liquid flows, thus making the plunger 402 applicable to high rate gas wells (e.g. over about 200 kscf/d).

Another illustrated aspect of the present disclosure includes the center cylindrical part 404 configured to hold the plug mechanism 406 and guide the valve stem portion of the plug mechanism 406. Advantageously, the ball plug 406 is aligned with the center line of plunger 402.

Still another exemplary aspect of the present disclosure is represented by the two-stage locking mechanism 407, and 416 a-416 c. One function of the locking mechanism is to ensure that the plug and valve element 406 remains in the desired position during plunger operations. The locking mechanism 407, and 416 a-416 c prevents the plug element 406 from undesirably engaging when the plunger 402 splashes at a high descending velocity into continuous water or a water slug. On the other hand, the locking mechanism 407, and 416 a-416 c can be unlocked by a small continuous force when the plunger 402 reaches a subsurface bumper spring at the bottom of the well. Such an arrangement beneficially allows the plunger 402 to have “automatic” actuation between the open and closed positions, rather than requiring external controls or signals to open or close the plunger. However, automatic operation of the plunger 402 does not require the elimination of control devices and may be used with control devices for certain circumstances (e.g. optimization of plunger lift operation). Note that the balls and spring locking elements are only one exemplary embodiment that may be used in the presently disclosed plunger 402. Other locking mechanisms may include magnetic latching means, compression ring engagement means, or some other equivalent arrangement known by persons of ordinary skill in the art.

In particular, the locking mechanism 407, and 416 a-416 c of plunger 402 comprises grooves 416 b on both the actuation member 407 and center cylinder 404. There are two perforated grooves or holes (retaining the bearing balls 416 a) on the inner cylinder of the plug mechanism 406, perpendicular to the axis, phasing 180 degrees, and crossing the center. The holes, together with the grooves 416 b form a housing for the balls 416 a. The balls 416 a can move outwards or inwards depending on the force direction and availability of space (e.g. groove). If there is not space for the ball to move into, either outwards to the outmost cylinder 403 of the center body or inwards to the actuation member 407, then the ball 416 a will lock the two pieces together that host the balls.

The actuation member 407 plays an important role for the locking mechanism. The mechanism is designed to lock the plug valve 406 in the outer center body 404 when the plunger descends against upwards fluid flow. When the actuation member 407 is at its lower most position, the groove 416 b on the rod is away from the balls so that the mechanism is locked.

When the plunger 402 reaches the bottom of a well, the actuation member 407 touches the bumper head at a bottom bumper spring assembly and stops moving first while all other components of the plunger 402 continue descending under the gravity force. When the plug mechanism 406 is stopped by the bottom bumper spring, the actuation member 407 is pushed into the plug mechanism 406 so that the groove 416 b on the actuation member 407 is facing the balls 416 a. Since a space is opened for the balls 416 a to move into, the mechanism is unlocked. As the result, the cylindrical body 403 and the center cylinder 404 are allowed to continue descending until the cylindrical body 403 contacts the plug 406 so that the plunger opening 414 is closed. Then, wellbore flow and pressure will push the plunger 402 and a water column upward to a surface.

When the plunger 402 is closed and travels upwards, the locking mechanism is ineffective because the differential pressure across the plunger 402 will keep the plunger plug valve 406 closed until the plunger 402 reaches the surface. When the plunger 402 reaches the surface, an extension rod on a wellhead assembly will knock the plug valve 406 open and push the balls 416 a into the groove 416 b on the center cylinder 404 so that the plunger 402 is locked open. As the result, the plunger 402 will descend in the wellbore starting a new tripping cycle.

One optional aspect of the present disclosure is represented by the internal fishing neck 419 on the inner profile of the tubular cylindrical plunger body 403. The fishing neck 419 can be used for retrieving the plunger 402 in the well in case of plunger failure.

Note that the plunger 402 may further include 0-ring seals on both ends of each element that experiences relative movement (e.g. 404, 406, and 407). These seals are designed to prevent solids and debris such as formation sands or fine particles from entering the locking mechanism and thus endangering the functionality of the plunger.

Further note that there is also a support element connecting the cylinder body 403 and the center cylinder 404. This element is not shown in FIG. 1A, but a similar element is shown in FIG. 1C.

FIGS. 4B-4C show three longitudinal-cut, cross-sectional views of two alternative embodiments of the one-piece plunger apparatus of FIG. 1A including two-stage locking mechanisms. As such, FIGS. 4B-4C may be best understood with reference to FIG. 1A. FIG. 1B shows alternative plunger 451 in a closed view 450 and an open view 460. The plunger 451 generally includes the same features as the plunger embodiment 402, but illustrates an alternative locking mechanism 452-453, and 456, and an inner insertion rod 458 with an end-cap 454 integrated therewith.

In the embodiment of FIG. 1B, plunger 451 illustrates another locking mechanism. Plunger 451 utilizes a compression spring 452 directly against the impact force on the rod 458 when the plunger 451 splashes into a water slug or column. For each of the plungers 402 and 451, the springs 416 c and 452 have a spring rate configured to actuate the inner insertion rods 407 and 458 (e.g. the plug mechanism 406 will move to the closed position) when the plunger 402 or 451 touches a solid surface. Because plunger 451 uses a compression spring 452 to keep the inner rod 458 extended, this design does not rely on other forces, such as impact force, to return the rod 458 to the locked (open) position.

FIG. 1C shows alternative plunger 471 in a closed view 470 and an open view 480. The plunger 471 generally includes the same features as the plunger embodiments 402 and 451, but illustrates an alternative locking mechanism 472-473, and 476 housed in a support element 482 and an inner insertion rod 478 with an end-cap 474 integrated with a downstream portion of the stem portion of the plug mechanism 406. The locking mechanism includes an inner insertion rod 478 with an end-cap 474, spring 472 and ball 473 elements interoperable with the inner insertion rod 478 and a groove element 476 to form a locking apparatus.

FIG. 1D shows an embodiment of the one-piece profile 160 with an exemplary one-stage locking mechanism. As such, FIG. 1D may be best understood with reference to FIGS. 1A-1C. In particular, plunger configuration 491 in view 490 shows the plunger 402 in the closed position and view 495 with plunger 402 in the open position. The plunger 402 includes a support member 482, a center cylinder 494, a plug or valve mechanism 492 having an end or head portion with a streamlined shape and a one-stage locking mechanism comprising two spring-loaded latches 496A and 496B with balls and two annular grooves 498A and 498B for receiving the balls in the locked or open position.

The one-stage locking mechanism 496A-496B and 498A-498B is configured to impart a force on the plug mechanism 492 in the open position sufficient to maintain the plug mechanism in the open position as the plunger apparatus 491 falls through continuous water. In the closed position 495, the locking mechanism does not hold the plug mechanism 492 in place. Instead, the pressure from produced fluids (e.g. gas and some water) will force the plug mechanism into the plunger body to maintain the closed position as the plunger 491 trips up to the top of the wellbore. Beneficially, the one-stage locking mechanism does not require an actuation member 144 or 407 and may be easier to manufacture and more robust in operation than the two-stage locking mechanisms disclosed in FIGS. 4A-4C.

Yet another exemplary aspect of the present disclosure comprises the support or fin element 482, which may be configured to fasten to the center element 404 and house the locking mechanism 472-473. No particular requirement is given for the number of support elements 482, but minimal drag is desired.

FIGS. 1E-1F show external views of the exemplary one-piece plunger of FIGS. 1A-1D. As such, FIGS. 1E-1F may be best understood with reference to FIGS. 1A-1D. View 400D shows the open position of the plunger 402 (which may also be plunger 451 or 471), while view 420D shows the closed position. Note that the depicted sealing mechanisms 418 on the outer perimeter of the plunger 402 are standard turbulent sealers, but may be any one of a pad plunger type, brush type, or wobble-washer type. View 440D shows the plunger 402 in the open position and further shows sealing mechanisms 418′ configured to induce an azimuthal variation of the toroidal vortex of a turbulent sealer, as discussed above.

In the exemplary embodiment 440D, the side-wall or outer wall may include sealing mechanisms 418′ having a fluid sealing element in the cavity of the sealing mechanism configured to induce an azimuthal variation of the toroidal vortex (e.g. “3-D vortex generator”). The 3-D vortex generator may be understood as a “sharp” edge in a fluid flow cavity (e.g. the sealing mechanism 418′) configured to disrupt the axial-symmetry of the cavity such that the 3-D vortex generator creates a complex vortical structure when fluid flows over or through the 3-D vortex generator. Examples of a 3-D vortex generator include a small cut 418′ in the front edge of a turbulent sealer 418 (as shown in FIG. 1E), an angular sealing mechanism 418 (making a cavity that looks like a “V”), and a sealing mechanism 418 with a sharp step therein. In addition, it is preferred that the fluid sealing element of one sealing mechanism (or cavity) is axially mis-aligned with a fluid sealing element of an adjacent sealing mechanism, as shown.

Beneficially, the improved sealing mechanisms 418′ are configured to reduce or minimize both the downward flow of water and the upward flow of gas in the space between the outer surface of the plunger cylinder 403 and the tubular walls. This not only reduces the leak of lifted water during the ascent, but also maintains the gas pressure underneath the plunger 402, thus increasing the overall efficiency of the system. These sealing mechanisms are further described and disclosed in commonly assigned U.S. Provisional Patent Application Nos. 61/222,788 and 61/239,320 entitled “FLUID SEALING ELEMENTS AND RELATED METHODS” and filed on 2 Jul. 2009 and 2 Sep. 2009, respectively. Each of these applications are incorporated herein by reference in their entirety for all purposes, except the portions dealing with devices other than plungers.

It should be noted that the sealing mechanisms 418′ are configured to provide a continuous interface between a liquid and a pressurized gas when the plunger 402 ascends in a well with the plug mechanism 406 in the closed position. Additionally, the sealing mechanisms 418 may be slightly smaller than a diameter of a well tubular to account for irregularities and/or paraffin, wax, salt, or other buildup on the inside of the tubular walls. As discussed above, the outer diameter of the plunger body, with or without the sealing mechanisms 418, may be slightly less than the diameter of the tubular string in which the plunger is intended to travel. Other exemplary side-wall geometries include, for example, wobble washers (e.g. variable or shifting ring side-wall), a brush-type side-wall, an expanding blade assembly (e.g. spring-loaded interlocking pads), or any combination thereof. These geometries and their capabilities and limitations are well-known to those of skill in the art and may be found, for example in U.S. Pat. No. 7,383,878, the portions of which dealing with side-wall geometries are hereby incorporated by reference.

In another embodiment of the plungers 402, 451, 471, or 491 disclosed herein, a friction reducing coating (FRC) may be applied to some portion or all of the portions of the plunger, which may be exposed to dynamic fluid forces and which it is desired to reduce such forces. For example, such a coating may be applied to the ball or plug portion of the plug mechanism 406, the leading or front edge of the plunger body 403, the extended second end 410 of the actuation member 407, the outer surface of the plunger (including sealers 418), or any other exposed portion. Further, it is desirable that the locking mechanism have increased durability. As discussed, the conditions of the plunger operation also require durability and resistance to wear, so such a coating or surface must also be hard and durable.

Examples of potentially viable coating or materials options for a FRC include diamond-like carbon (DLC), advanced ceramics (e.g. TiN, TiB.sub.2), near-frictionless carbon (NFC), TEFLON™, graphite, chemical-vapor deposition (CVD) diamond, and other such surface coatings.

FIGS. 2A-2D illustrate a series of schematics showing a single cycle of the automatic plunger lift process utilizing the plunger of FIGS. 1A-1D. As such, FIGS. 2A-2C may be best understood with reference to FIGS. 1A-1D. FIG. 2A illustrates a view 500 showing a top portion of a wellbore tubular 502, a wellhead assembly 512 (including a cap, a bumper spring, a striker pad), an extension rod 514, an exemplary plunger 402, and a production flow line or pipe 506. The view 500 also includes arrows showing the direction of travel 520 of the plunger 402, direction of travel of gas 518 through the flow channel 415 and the tubular 502, and the direction of travel of gas 522 through the production pipe 506. Note that other common components on the wellhead (e.g. lubricator, valves, etc.) are not explicitly illustrated, but a person of ordinary skill in the art will understand how to implement such devices based on the disclosure herein.

FIG. 2B illustrates the case where the plunger 402 is descending while the well 503 is producing water and gas 504 via perforations 506. The well 503 further includes a bumper spring assembly 508. Arrow 510 shows the direction of gas flow and arrow 512 shows the direction of plunger descent. Since the plug valve 406 is open, produced fluids can pass through the plunger 402. When the drag force due to fluid flow (gas and produced liquids) on the plunger 402 is not large enough to balance the plunger force of gravity, the plunger 402 will descend against the wellbore producing fluid flows.

FIG. 2C illustrates the condition where the plunger 402 is stopped by the subsurface bumper spring 508 and the plunger 402 is in closed state and ready for tripping up (e.g. return to the surface).

FIG. 2D illustrates the plunger 402 being pushed by the wellbore (gas) pressure up the well as indicated by arrow 510 to the surface near the wellhead assembly 512 and extension rod 514 while the water is being pushed into the production flow line 506 as shown by arrow 522.

FIGS. 3A-3B illustrate the stages of the automatic plunger of FIGS. 1A-1F being closed by the impact at the subsurface bumper spring of FIGS. 2B and 2C. As such, FIGS. 3A-3B may be best understood with reference to FIGS. 1A-1F, 2B and 2C. The illustration 600, in schematic 602 shows the descending plunger 402 is approaching the subsurface bumper spring assembly 508. Schematic 604 shows the moment that the plunger 402 reaches the bumper spring assembly 508 and the insertion rod 407 of the plunger locking mechanism contacts the plunger stopper on top of the bumper spring assembly. Schematic 606 shows the insertion rod 407 as it is pushed into the plug or valve mechanism 406 and the plunger valve element is unlocked. Schematic 608 shows the valve mechanism 406 is pushed up while the plunger body 403 continues to descend. Schematic 610 shows the moment when the cylindrical plunger body 403 contacts and sits on top of the plug or valve mechanism 406 such that the plunger opening 414 is closed. Schematic 612 shows that as the momentum of descending plunger 402 tends to drive the plunger to move downwards, the subsurface bumper spring in assembly 508 is compressed until the plunger totally stops its descent.

In FIG. 3B, the illustration 620 in schematic 622 shows the descending plunger 491 is approaching the subsurface bumper spring assembly 508. Schematic 624 shows the moment that the plunger 491 reaches the bumper spring assembly 508. Schematic 626 shows the valve mechanism 492 is stopped while the plunger body 403 continues to descend until the moment when the cylindrical plunger body 403 contacts and sits on top of the plug or valve mechanism 492 such that the plunger opening 414 is closed. Schematic 628 shows that as the momentum of descending plunger 491 tends to drive the plunger to move downwards, the subsurface bumper spring in assembly 508 is compressed until the plunger totally stops its descent.

FIGS. 4A-4B illustrate the stages of the automatic plunger of FIGS. 1A-1F being closed by the impact at the wellhead assembly of FIGS. 2A and 2D. As such, FIGS. 1A-1B may be best understood with reference to FIGS. 1A-1F, 2A, and 2D. View 700 shows schematic 702 illustrating the plunger 402 being pushed by wellbore gas pressure and approaching the wellhead stopper assembly 512. Schematic 704 shows that the plunger insertion rod 407 contacts the extension rod 514 of the plunger stopper assembly 512. Schematic 706 shows that as the insertion rod 407 is stopped by the wellhead assembly 512, the stem of the valve element 406 moves up, contacts the step end of the insertion rod 407, and stops moving. Schematic 706 further shows the plunger body 403 continuing to move upwards from the momentum of the plunger 402. Schematic 708 shows that the valve element 406 is locked in its open position as it is pushed into place by the extension rod 407. The momentum continues to carry the plunger 402 up in schematic 710. As the stopper 512 absorbs all the kinetic energy of the plunger 402, the plunger velocity is finally reduced to zero in schematic 712. At this moment, the plunger 402 is ready to fall to start a next tripping cycle.

In FIG. 4B, view 720 shows schematic 722 illustrating the plunger 491 being pushed by wellbore gas pressure and approaching the wellhead stopper assembly 512. Schematic 724 shows the plunger 491 closer to the wellhead stopper assembly 512. Schematic 726 shows that the second end of the plug assembly 492 contacts the extension rod 514 of the plunger stopper assembly 512. Schematic 728 further shows the plunger body 403 continuing to move upwards from the momentum of the plunger 491 compressing the spring in the plunger stopper assembly 512. As the stopper 512 absorbs all the kinetic energy of the plunger 491, the plunger velocity is finally reduced to zero in schematic 728. At this moment, the plunger 491 is ready to fall to start a next tripping cycle (unless it is caught and held at the top of the wellbore).

FIG. 5 illustrates a flow chart showing the steps of a method of producing hydrocarbons using the plunger of FIGS. 1A-1F in the cycle of FIGS. 2A-2D. As such, FIG. 8 may be best understood with reference to FIGS. 1A-1F and 2A-2D. The process 800 includes providing 802 a hydrocarbon well 503 having a wellbore tubular 502, a flow line 506 in fluid communication with the wellbore, a top portion 512 with a tubular head stopper, and a bottom portion with a bottom bumper stopper assembly 508. Next, producing 804 a volume of liquids and a gaseous stream 504 imparting a gaseous pressure from the bottom portion to the top portion of the wellbore 503. Then, operating 806 an automatic plunger 402 or 491 in the wellbore 503 in a plunger lift cycle, the lift cycle comprising: lifting 808 at least a portion of the produced volume of liquids 504 towards the top portion of the wellbore and out of the flow line 506 utilizing the gaseous pressure from the bottom portion to the top portion of the wellbore, wherein the automatic plunger 402 or 491 is in a closed position; impacting 810 the tubular head stopper 514 with the automatic plunger 402 or 491 causing the automatic plunger 402 or 491 to automatically change its operating state from the closed position to an open position; descending 812 the automatic plunger 402 or 491 in the open position to the bottom of the wellbore 503, wherein a gravitational force on the plunger 402 or 491 is greater than a combined drag force and pressure force on the plunger apparatus 402 or 491 caused by the passage of the volume of fluids and the gaseous stream; impacting 814 the bottom bumper stopper 508 with the automatic plunger 402 or 491 causing the automatic plunger 402 or 491 to automatically change its operating state from the open position to the closed position; and repeating 816 the artificial lift cycle.

Note that the disclosed method may be optimized, altered or improved in a variety of ways depending on the flow rate of the well, diameter of the well, composition of the fluids produced in the well, and other factors. One particular exemplary feature includes controlling the plunger lift cycle by catching the automatic plunger apparatus 402 or 491 at or near the top portion of the wellbore; holding the automatic plunger apparatus 402 or 491 for a period of time; and releasing the automatic plunger apparatus 402 or 491 upon the occurrence of a condition in the wellbore. One exemplary condition may be shut-in of the well for maintenance or safety reasons. Another exemplary condition may be that there is simply not much liquid loading in the well and therefore no need to immediately send the plunger to the bottom to bring up liquids.

FIG. 6 illustrates a method of manufacturing the plunger of FIGS. 1A-1F. As such, FIG. 6 may be best understood with reference to FIGS. 1A-1F. The method 900 includes forming 902 the plunger body 403 out of a single piece of material; fixedly attaching 904 the support element 404 to the flow channel 415; slidably attaching 906 the plug or valve element 406 to the support element 404; and optionally slidably attaching 908 the locking apparatus 407 to the valve element 406. In the case of the one-stage locking mechanism arrangement 491, there is no locking apparatus 407, so this step is not necessary.

The method may further include forming multiple turbulent sealers each having at least one vortex generator on an outer surface of the plunger body; and applying a friction reduced coating on at least a portion of the plunger, wherein the FRC is selected from the group consisting of: diamond-like carbon (DLC), advanced ceramics, graphite, and near-frictionless carbon (NFC). Any workable manufacturing technique may be applied, but it is contemplated that casting, welding, etching, and lathing techniques may be used alternatively or in combination to manufacture the disclosed plunger apparatus.

FIGS. 7-10 illustrate some exemplary embodiments of the presently disclosed technology utilizing on-board seal actuation manipulation by electrical and/or fluid-powered force mechanisms for manipulating the selective actuation of the external seal assembly. FIG. 7 illustrates a wellbore conduit 34, such as a production tubing or production casing, and a plunger body 403 positioned therein. The Exemplary plunger embodiment illustrated in FIG. 7 and having throughbore 415 demonstrates a plunger assembly 730 including selectively inflatable seals and a plunger 406 including unlocking rod embodiment 410, as illustrated in FIG. 1A. The plug 406 is illustrated in the closed position with respect to the body 403. Seals 423 are selectively actuated into the deployed position, while seals 421 are unactuated, still in the recessed position, with respect to the plunger body 403. Plunger 730 also includes an actuating system comprising a controller 435, such as a battery powered controller having a processor and instruction programming. The processor may be responsive to measure or otherwise provided inputs to the controller. Power source 433 may power the controller 435 as well as a motor and pump assembly 431. Fluid reservoir 429 may provide a source of power fluid. Control lines 427 may connect the pump and fluid reservoir with the inflatable seals 421, 423. Valves 425 may be selectively actuated by the controller 435 between an open and closed position to enable selectively actuating the seals, by permitting inflating or deflating each of the seals 421, 423, as appropriate. FIG. 7 illustrates one seal set, an upper and lower seals, 423, in the deployed position, with seals 421 in the retracted position. As seal 423 wears out, rather than having to replace all of the seals, successive seals that have not been previously exposed to the wellbore wall 34 through plunger travel may be selectively added to deployment with the previously deployed seal, or in lieu of the previously deployed seal. FIG. 8 illustrates plunger embodiment 740 exhibiting seal 421′ added to the deployed seal set 423 of FIG. 7, to extend plunger run-life or seal life, or merely to effect longer plunger run-life.

FIGS. 9 and 10 are somewhat analogous to FIGS. 7 and 8, respectively, except the embodiments 750 and 760 of FIGS. 9 and 10 may utilize a plug or valve assembly that does not include the plug 406 or plug-type of one or two-piece plunger embodiment. As the plungers 750 and 760 may utilize a controller, on-board power, and motor power, a rotatable internal valve assembly may be provided in plungers 750 and 760 in lieu of a plunger. Such embodiments are discussed below in more detail.

FIG. 11 is a schematic cross-sectional view of illustrative, non-exclusive examples of a gaseous hydrocarbon well 20 that may include and/or utilize a plunger 50 according to the present disclosure. Gaseous hydrocarbon well 20 also may be referred to herein as a hydrocarbon well 20 and/or simply as a well 20. Well 20 includes a wellbore 30 that extends between a surface region 22 and a subterranean formation 26 that is present within a subsurface region 24. Well 20 further includes a conduit body 34 that defines a wellbore conduit 36. The wellbore conduit extends within the wellbore, is defined within the wellbore, and/or includes at least a portion of the wellbore.

Plunger 50 is located within a target region 38 of wellbore conduit 36. Target region 38 of wellbore conduit 36 may include and/or be any suitable portion of the wellbore conduit that is located downhole from surface tree 27, that is located and/or defined within subsurface region 24, that is located and/or defined within subterranean formation 26, and/or in which liquid 44 collects. As illustrative, non-exclusive examples, target region 38 may include, be located within, and/or be defined within a portion of subsurface region 24 that provides the wellbore fluid stream to the wellbore conduit and/or within a portion of the wellbore conduit that is distal from an uphole end of the wellbore conduit. As another illustrative, non-exclusive example, target region 38 may be at least a threshold distance from surface region 22 along a length of wellbore 30. Illustrative, non-exclusive examples of the threshold distance include threshold distances of at least 100 meters (m), at least 250 m, at least 500 m, at least 750 m, at least 1,000 m, at least 1,250 m, at least 1,500 m, at least 2,000 m, at least 3,000 m, at least 4,000 m, at least 5,000 m, at least 7,500 m, or at least 10,000 m.

As discussed in more detail herein, plunger 50 may be configured to have and/or define a low fluid drag state 64 and to rest, reside, remain and/or be located within target region 38 of wellbore conduit 36 while a wellbore fluid stream 42 flows past the plunger in an uphole direction 80 within the wellbore conduit. In addition, plunger 50 may be configured to selectively transition from the low fluid drag state to a high fluid drag state 66 responsive to a variable associated with the wellbore fluid stream being within a threshold range. Upon transitioning to the high fluid drag state, the plunger may be conveyed within wellbore conduit 36 in uphole direction 80, as illustrated in dashed lines in FIG. 1, by and/or with wellbore fluid stream 42. This may permit plunger 50 to urge and/or convey a liquid 44 and/or a solid material 46, which may be present within wellbore conduit 36, in the uphole direction. This conveying may thereby permit removal of the liquid and/or the solid material from the wellbore conduit and/or decrease a resistance to the flow of wellbore fluid stream 42 from the subterranean formation, within the wellbore conduit, in the uphole direction, and/or from the gaseous hydrocarbon well.

The variable associated with the wellbore fluid stream may include any suitable variable that is indicative of the presence of, or the presence of at least a threshold volume of, liquid 44 within target region 38 of wellbore conduit 36. Additionally or alternatively, when greater than the threshold volume of liquid 44 is present within target region 38, the variable associated with the wellbore fluid stream is within the threshold range. Illustrative, non-exclusive examples of the variable associated with the wellbore fluid stream may be or include a pressure of the wellbore fluid stream, a density of the wellbore fluid stream, a temperature of the wellbore fluid stream, and/or a flow rate of the wellbore fluid stream. As discussed in more detail herein, the systems and/or methods may monitor and/or detect the magnitude and/or the rate of change of the variable.

Subsequent to being conveyed in uphole direction 80, plunger 50 may transition back to the low fluid drag state 64. This transitioning may occur, for example, after the plunger reaches an uphole end of wellbore conduit 36, and/or urges liquid 44 and/or solid material 46 in uphole direction 80 and/or from wellbore conduit 36. This may permit the plunger to fall, such as under the influence of gravity, in a downhole direction 82 and/or toward target region 38 within wellbore conduit 36. The plunger then may rest, reside, remain and/or be located within the target region of the wellbore conduit, such as for at least a threshold maintaining time, before once again transitioning to the high fluid drag state and being conveyed in uphole direction 80 with wellbore fluid stream 42. This process may be repeated any suitable number of times and/or with any suitable frequency to remove liquid 44 and/or solid material 46 from the wellbore conduit.

Wellbore conduit 36 may be defined by any suitable structure and/or conduit body 34. As an illustrative, non-exclusive example, wellbore conduit 36 may be defined by (or conduit body 34 may be) wellbore 30. As another illustrative, non-exclusive example, wellbore conduit 36 may be defined by (or conduit body 34 may be) a casing string that extends within wellbore 30. As yet another illustrative, non-exclusive example, wellbore conduit 36 may be defined by (or conduit body 34 may be) a tubing or production string that extends within wellbore 30.

As illustrated in FIG. 11, wellbore conduit 36 may define an at least substantially constant cross-sectional shape and/or area along a length thereof. However, it is also within the scope of the present disclosure that wellbore conduit 36 may include and/or be a tapered wellbore conduit 36 that defines a progressively smaller cross-sectional area as the wellbore conduit extends farther from surface region 22 along the length of the wellbore conduit. The tapered wellbore conduit may taper gradually and/or in discrete steps, or stages. When the wellbore conduit is a tapered wellbore conduit, plunger 50 may be adapted, configured, and/or designed to adjust an outer diameter thereof to correspond to an inner diameter of the wellbore conduit at a given location within the wellbore conduit. This may permit the plunger to maintain sufficient fluid drag there-past to be conveyed in the uphole direction with wellbore fluid stream 42 despite changes in the cross-sectional shape and/or area of the wellbore conduit.

As illustrated in solid lines in FIG. 1, wellbore 30 may include and/or be a vertical, or at least substantially vertical, wellbore 30 (or wellbore conduit 36 may include and/or be a vertical, or at least substantially vertical, wellbore conduit 36). However, and as illustrated in dash-dot lines in FIG. 1, wellbore 30 (or wellbore conduit 36) also may include and/or define one or more horizontal and/or deviated regions. As further illustrated in FIG. 1, target region 38 may be located in any suitable portion of wellbore conduit 36, including a vertical portion, a deviated portion, and/or a horizontal portion of the wellbore conduit. When target region 38 is located within a deviated and/or horizontal portion of wellbore conduit 36, a momentum of plunger 50 may be utilized to carry the plunger into the target region when the plunger is conveyed in downhole direction 82 and/or located within the wellbore conduit.

Target region 38 of wellbore conduit 36 may include and/or be any suitable portion of the wellbore conduit that is located downhole from surface tree 27, that is located and/or defined within subsurface region 24, that is located and/or defined within subterranean formation 26, and/or in which liquid 44 collects. As illustrative, non-exclusive examples, target region 38 may include, be located within, and/or be defined within a portion of subsurface region 24 that provides the wellbore fluid stream to the wellbore conduit and/or within a portion of the wellbore conduit that is distal from an uphole end of the wellbore conduit. As another illustrative, non-exclusive example, target region 38 may be at least a threshold distance from surface region 22 along a length of wellbore 30. Illustrative, non-exclusive examples of the threshold distance include threshold distances of at least 100 meters (m), at least 250 m, at least 500 m, at least 750 m, at least 1,000 m, at least 1,250 m, at least 1,500 m, at least 2,000 m, at least 3,000 m, at least 4,000 m, at least 5,000 m, at least 7,500 m, or at least 10,000 m.

As illustrated in FIG. 11, well 20 further may include a downhole support structure 97. Downhole support structure 97 may be configured to support, locate, and/or retain plunger 50 when the plunger is located within target region 38 of wellbore conduit 36. As discussed in more detail herein, plunger 50 may include a power source 94, such as a battery. Under these conditions, downhole support structure 97 may include a downhole electrical connection 98 that is configured to provide an electric current to power source 94, such as to charge the power source. As also discussed in more detail herein, plunger 50 may include a detector 92 that is configured to detect the variable associated with the wellbore fluid stream and/or one or more other variables that may be representative of conditions proximal to plunger 50 within wellbore conduit 36. Downhole support structure 97 also may include a downhole data transfer structure 99 that may be configured to permit and/or facilitate data transfer to and/or from plunger 50.

Well 20 also may include an uphole support structure 28. Uphole support structure 28 which may be associated with, near, and/or proximal to an uphole end of wellbore 36, may be associated with, near, and/or proximal to a surface tree 27 that is associated with well 20 and/or that is configured to selectively regulate flow of wellbore fluid stream 42 from well 20. As a further example, uphole support structure 28 may be located within a lubricator 32 of surface tree 27. Similar to downhole support structure 97, uphole support structure 28 may include an uphole electrical connection 29 and/or an uphole data structure 31, which may be at least substantially similar to downhole electrical connection 98 and or downhole data transfer structure 99. When plunger 50 is conveyed in uphole direction 80, near surface region 22, into surface tree 27, and/or into contact with uphole support structure 28, the plunger may be retained on uphole support structure 28 to permit charging of power source 94 and/or to permit data transfer to and/or from the plunger.

Plunger 50 may include any suitable structure that may be conveyed within wellbore conduit 36 to selectively define and/or transition between low fluid drag state 64 and high fluid drag state 66, and/or may urge or otherwise remove liquid 44 and/or solid material 46 from wellbore conduit 36. Plunger 50 further is configured to define and/or transition between low fluid drag state 64 and high fluid drag state 66, and/or may urge or otherwise remove liquid 44 and/or solid material 46 from wellbore conduit 36. As an illustrative, non-exclusive example, plunger 50 may include a drag-regulating structure 60, which is configured to selectively vary a fluid drag therepast, thereby transitioning, or permitting plunger 50 to transition, between the low fluid drag state and the high fluid drag state. High fluid drag state merely means a drag value that is greater than the low fluid drag state, but generally means wherein the plunger is transitioned from a state that permits the plunger to fall within the wellbore or remain at rest within the wellbore, to a state that permits the plunger to move uphole toward the surface, such as when unloading liquid from the wellbore. As another illustrative, non-exclusive example, plunger 50 may include and/or at least partially define a flow-through opening 62, which is configured to permit wellbore fluid stream 42 to flow therethrough at least when plunger 50 is in low fluid drag state 64. Illustrative, non-exclusive examples of plungers 50, drag-regulating structure 60, flow-through openings 62, components thereof, features thereof, and/or operation thereof are discussed in more detail herein. For purposes herein the drag-regulating structures may refer to components within the plunger throughbore or central flow passage, as well as the actuatable external seal assembly that is operatively provided on or within an outer surface of the plunger body. In the presently disclosed embodiments, the drag-regulating structures will always include at least the actuatable external seal assembly components, and may optionally (e.g., may or may not) include components fluid flow regulating valve components that regulate or control fluid flow through the internal passage or throughbore of the plunger body. Some embodiments may include both the actuatable external seal assembly and the internal valve mechanisms, while other embodiments may include the actuatable external seal assembly and a plug-type valve, as illustrated in Figures for controlling fluid flow through the internal throughbore of the plunger body. The external seal assembly may be actuatable either independent from actuation of the internal valve mechanisms (or plug) or the external seal assembly may be actuatable in conjunction with or responsive to actuation of the internal valve mechanisms. For example, a controller may control each of the external seal assembly independent from control of the internal valve assembly, or may control one or the other such that adjustment of one translates to both.

As discussed herein, the low fluid drag state may define a lower relative resistance to fluid flow past the plunger within the wellbore conduit, while the high fluid drag state may define a higher relative resistance to fluid flow past the plunger within the wellbore conduit. Thus, transitioning from the low fluid drag state to the high fluid drag state also may be referred to herein as increasing the resistance to fluid flow past the plunger (internally, externally, or both) within the wellbore conduit. Conversely, transitioning from the high fluid drag state to the low fluid drag state also may be referred to herein as decreasing the resistance to fluid flow past the plunger within the wellbore conduit. The resistance to fluid flow past the plunger may correspond to a pressure drop across the plunger within the wellbore conduit (with a higher resistance to fluid flow corresponding to a higher pressure drop) and/or to a fluid drag force on the plunger within the wellbore conduit (with a higher resistance to fluid flow corresponding to a higher fluid drag force). As discussed in more detail herein, transitioning between the high fluid drag state and the low fluid drag state may include changing a cross-sectional area of flow-through opening 62, though this is not required in all embodiments, as deploying the external seal assembly alone will also change the cross-sectional flow area and fluid drag force and changing the external seal assembly is all that is required to change the fluid drag force according to this present disclosure. The high and low fluid drag states additionally or alternatively may synonymously be referred to as high and low fluid drag configurations, expanded and contracted configurations, deployed and retracted seal configurations, and/or conveying and maintaining configurations.

Plunger 50 further may include a controller 90. The controller may be adapted, configured, designed, and/or programmed to control the operation of plunger 50. As an illustrative, non-exclusive example, controller 90 may be programmed to control and/or regulate the transitioning of plunger 50 between the low fluid drag state and the high fluid drag state. As another illustrative, non-exclusive example, controller 90 may be programmed to perform any suitable portion of methods 100, which are discussed in more detail herein. This may include performing at least the maintaining at 120 and the transitioning at 135 of subsequently discussed methods 100. This also may include storing the methods within an internal memory 96 of the controller and/or retrieving the methods from the internal memory to permit and/or facilitate execution of the methods.

Plunger 50 also may include and/or controller 90 may be in communication with detector 92, as discussed in more detail herein. In addition, plunger 50 may include a transmitter 91 and/or a receiver 93. Transmitter 91 and/or receiver 93 may permit controller 90 to transmit and/or receive data, as discussed in more detail herein.

It is within the scope of the present disclosure that plunger 50 and/or controller 90 thereof may be adapted, configured, designed, and/or programmed to release, or regulate a release of, supplemental material 54 into wellbore conduit 36. As an illustrative, non-exclusive example, plunger 50 may include a supplemental material reservoir 52, and controller 90 may direct plunger 50 to release supplemental material 54 from supplemental material reservoir 52 and into the wellbore conduit. As another illustrative, non-exclusive example, plunger 50 and/or downhole support structure 97 may be configured to release supplemental material 54 upon and/or concurrent with transitioning of the plunger to the high fluid drag state. As a further illustrative, non-exclusive example, controller 90 may direct supplemental material 54 to be released into wellbore conduit 36 from surface region 22. Illustrative, non-exclusive examples of supplemental material 54 include any suitable foaming agent, soap, surfactant, lubricant, and/or mixtures thereof. Additional illustrative, non-exclusive examples of supplemental material 54 include inhibitors, such as a scale inhibitor, corrosion inhibitor, paraffin inhibitor, etc.

As discussed in more detail herein, plunger 50 may be adapted, configured, sized, and/or designed to permit wellbore fluid stream 42 to flow there-past when the plunger is located within target region 38 of wellbore conduit 36 and the plunger is in the low fluid drag state. It is within the scope of the present disclosure that the wellbore fluid stream may flow past the plunger in any suitable manner. As an illustrative, non-exclusive example, and as illustrated in FIGS. 13-26, plunger 50 may define an internal flow-through opening 62, and the wellbore fluid stream may flow through the internal flow-through opening. Such a flow-through opening also may be referred to herein as an internal flow-through opening 67.

As another illustrative, non-exclusive example, and as illustrated in FIGS. 19-20 and 27-29, plunger 50 and conduit body 34 together may define an annular flow-through opening 62 therebetween, and the wellbore fluid stream may flow through the annular flow-through opening. Such an annular flow-through opening may be external to and/or defined by an external surface of plunger 50 and also may be referred to herein as an external flow-through opening 68.

Wellbore fluid stream 42 may include any suitable wellbore fluid 40 that may flow from subterranean formation 26, may flow through wellbore conduit 36, and/or may be produced from gaseous hydrocarbon well 20. Generally, wellbore fluid stream 42 will include and/or be a gaseous stream and/or a vaporous stream, and illustrative, non-exclusive examples of wellbore fluid stream 42 include a gaseous hydrocarbon stream, a vaporous hydrocarbon stream, a methane stream, and/or a natural gas stream.

Liquid 44 may include any suitable liquid that may accumulate within wellbore conduit 36, may be present within wellbore conduit 36, and/or may (at least partially) restrict flow of wellbore fluid stream 42 within wellbore conduit 36. Illustrative, non-exclusive examples of liquid 44 include water and/or a liquid hydrocarbon. Solid material 46 may include any suitable solid, solid-like, and/or gel material that may accumulate within wellbore conduit 36, may be present within wellbore conduit 36, and/or may (at least partially) restrict flow of wellbore fluid stream 42 within wellbore conduit 36. Illustrative, non-exclusive examples of solid material 46 include a paraffin, a wax, and/or scale. Liquid 44 and/or solid material 46 present in wellbore conduit 36 generally may be referred to herein as wellbore material 48.

As used herein, uphole direction 80 may include any suitable direction that is along (or parallel to) a respective length (or portion) of wellbore conduit 36 and that is directed toward, or closer to, an intersection of the wellbore conduit with surface region 22 and/or toward surface tree 27, when present. Additionally or alternatively, moving an object in the uphole direction also may be described as moving the object in a direction along a trajectory of wellbore conduit 36 that tends to decrease a distance between the object and a surface terminal end 37 of wellbore conduit 36.

Conversely, downhole direction 82 may include any suitable direction that is along (or parallel to) the respective length (or portion) of wellbore conduit 36 and that tends to move away from the intersection of the wellbore with surface region 22, away from surface tree 27, away from surface terminal end 37, toward a subterranean terminal end 39 of wellbore conduit 36, and/or toward a toe 41 (when present) of wellbore conduit 36.

Surface tree 27 may include and/or be any suitable structure that may be configured to control and/or regulate at least a portion of the fluid flows into and/or out of well 20. As illustrative, non-exclusive examples, surface tree 27 may include one or more valves, spools, and/or fittings. Surface tree 27 also may be referred to herein as a Christmas tree 27, a surface valve assembly 27, and/or as a surface flow control assembly 27.

FIG. 12 is a flowchart depicting methods 100 according to the present disclosure of removing a liquid from a wellbore conduit of a gaseous hydrocarbon well with a plunger, while FIGS. 4-8 provide illustrative, non-exclusive examples of a process flow that may be utilized with a plunger according to the present disclosure and/or that may illustrate methods 100. Methods 100 may include locating the plunger within a target region of the wellbore conduit at 105 and/or powering the plunger at 110. Methods 100 include flowing a wellbore fluid stream within the wellbore conduit at 115 and maintaining the plunger in a low fluid drag state at 120. Methods 100 may include detecting a variable associated with the wellbore fluid stream at 125 and/or collecting downhole data at 130. Methods 100 further include transitioning the plunger to a high fluid drag state at 135 and may include releasing a supplemental material 54 into the wellbore conduit at 140. Methods 100 further include conveying the plunger in an uphole direction within the wellbore conduit at 145 and may include determining a status of the plunger during the conveying at 150, regulating a motion of the plunger at 155, collecting traverse data with the plunger at 160, producing a liquid from the gaseous hydrocarbon well at 165, adjusting a threshold range at 170, and/or repeating the methods at 175.

Locating the plunger within the target region of the wellbore conduit at 105 may include locating the plunger within any suitable target region of the wellbore conduit in any suitable manner. As an illustrative, non-exclusive example, the locating at 105 may include lubricating the plunger into the wellbore conduit. As another illustrative, non-exclusive example, the locating at 105 may include permitting the plunger to fall within the wellbore conduit under the influence of gravity and/or permitting the plunger to fall within the wellbore conduit concurrently with (and/or in a direction that is opposed to) the flowing at 115. It is within the scope of the present disclosure that the locating at 105 may include locating the plunger within the target region of the wellbore conduit without shutting in the well and/or without exposing the wellbore conduit to ambient atmospheric conditions and/or ambient atmospheric pressure.

As used herein, the phrase, “shutting in” may include and/or refer to sealing the hydrocarbon well, ceasing production of the wellbore fluid stream from the hydrocarbon well, and/or ceasing flow of the wellbore fluid stream in the uphole direction within the wellbore conduit. Traditional plungers may require that the hydrocarbon well be shut in to permit the traditional plunger to move in a downhole direction within the wellbore conduit. However, plungers according to the present disclosure, which define the low fluid drag state, may be configured to move in the downhole direction under the influence of gravity while the wellbore fluid stream is flowing in the uphole direction within the wellbore conduit.

Powering the plunger at 110 may include powering any suitable portion of the plunger in any suitable manner. As an illustrative, non-exclusive example, the powering at 110 may include providing an electric current to and/or from any suitable portion of the plunger. As another illustrative, non-exclusive example, and as discussed, the plunger may include a power source, such as a battery, and the powering at 110 may include powering with the power source. When methods 100 include the powering at 110, methods 100 further may include charging and/or re-charging the power source. This may include charging and/or re-charging the power source while the plunger is located within the target region of the wellbore conduit (as illustrated in FIG. 3) and/or charging and/or re-charging the power source while the plunger is located proximal to and/or near the surface region (as illustrated in FIG. 18). The charging and/or re-charging may occur while the plunger is supported by uphole or downhole support structure 28 and 97, such as when the plunger is in electrical contact with an uphole or downhole electrical connection 29 or 98 thereof. It is within the scope of the present disclosure that the charging and/or re-charging may include providing an electric current to the wellbore conduit to permit, facilitate, and/or accomplish the charging and/or re-charging. Additionally or alternatively, it is also within the scope of the present disclosure that the charging and/or re-charging may include generating the electric current within the wellbore conduit, such as by harvesting energy from the wellbore conduit.

Flowing the wellbore fluid stream within the wellbore conduit at 115 may include flowing the wellbore fluid stream within the wellbore conduit in an uphole direction. This may include flowing the wellbore fluid stream past the plunger while the plunger is located within the target region of the wellbore conduit, flowing the wellbore fluid stream in contact with the plunger while the plunger is located within the target region of the wellbore conduit, flowing the wellbore fluid stream through the plunger while the plunger is located within the target region of the wellbore conduit, and/or flowing the wellbore fluid stream through a flow-through opening that is at least partially defined by the plunger while the plunger is located within the target region of the wellbore conduit.

Maintaining the plunger in the low fluid drag state at 120 may include maintaining the plunger in the low fluid drag state while the variable associated with the wellbore fluid stream is outside a threshold range. The maintaining at 120 may include maintaining the plunger in the low fluid drag state during the flowing at 115, and a fluid drag on the plunger when the plunger is in the low fluid drag state may be sufficiently low to permit the plunger to remain within the target region of the wellbore conduit despite and/or during the flowing at 115. Additionally or alternatively, the maintaining at 120 also may include maintaining the plunger within the target region of the wellbore conduit, maintaining the plunger at least substantially motionless within the wellbore conduit, and/or maintaining the plunger in contact with a downhole support structure.

It is within the scope of the present disclosure that the maintaining at 120 may include maintaining the plunger in the low fluid drag state for at least a threshold maintaining time. Illustrative, non-exclusive examples of the threshold maintaining time include threshold maintaining times of at least 1 minute, at least 5 minutes, at least 10 minutes, at least 30 minutes, at least 1 hour, at least 2 hours, at least 5 hours, at least 12 hours, at least 1 day, at least 2 days, at least 3 days, or at least 1 week.

During the maintaining at 120, and as illustrated in FIG. 13, liquid 44 may collect within target region 38 of casing conduit 36 and/or may collect on an uphole side 56 of plunger 50. This liquid may block, occlude, resist, and/or increase a resistance to flow of wellbore fluid stream 42 in uphole direction 80 within wellbore conduit 36, thereby decreasing a production rate of the wellbore fluid stream from gaseous hydrocarbon well 20. Thus, it may be desirable to periodically remove this liquid from the wellbore conduit, as discussed.

Detecting the variable associated with the wellbore fluid stream at 125 may include detecting the variable with any suitable type and/or number of detector(s). The detecting at 125 may include detecting any suitable variable that is associated with the wellbore fluid stream, is indicative of one or more properties of the wellbore fluid stream, and/or is indicative of the presence of liquid within the target region of the wellbore conduit. The detecting at 125 may include detecting that the variable associated with the wellbore fluid stream is within the threshold range and/or outside the threshold range. Illustrative, non-exclusive examples of the variable associated with the wellbore fluid stream are discussed herein.

Collecting downhole data at 130 may include collecting any suitable downhole data with the plunger, with the detector, and/or with a controller that forms a portion of the plunger and/or that is in communication with the detector. The collecting at 130 may include collecting the downhole data while the plunger is within the target region of the wellbore conduit and/or during the maintaining at 120. Illustrative, non-exclusive examples of the collected downhole data include a downhole pressure of the wellbore fluid stream, a downhole flow rate of the wellbore fluid stream, a downhole temperature of the wellbore fluid stream, and/or a downhole density of the wellbore fluid stream. It is within the scope of the present disclosure that the collecting at 130 may include collecting a single data point, collecting the downhole data at a single point in time, and/or collecting the downhole data as a function of time. It is also within the scope of the present disclosure that the downhole data may include and/or be the variable associated with the wellbore fluid stream and/or that the collecting at 130 may be performed concurrently with, and/or may be a result of, the detecting at 125.

The collecting at 130 may include generating a database of downhole data. This database of downhole data may, at least temporarily, be stored within the plunger, such as within a memory device thereof. Additionally or alternatively, the downhole data and/or the database of downhole data may be transferred from the plunger, stored on another device, and/or utilized to document and/or model the behavior and/or performance of the hydrocarbon well. As an illustrative, non-exclusive example, and when methods 100 include the collecting at 130, the methods further may include conveying the data from the plunger and/or to the surface region. This may include conveying the data from the plunger in any suitable manner and/or at any suitable time during methods 100, such as during the charging and/or re-charging that is discussed herein with reference to the powering at 110 and illustrated in FIG. 8.

Transitioning the plunger to the high fluid drag state at 135 may include transitioning responsive to the variable associated with the wellbore fluid stream being within the threshold range. The transitioning at 135 may include increasing a resistance to fluid flow past the plunger within the wellbore conduit, which may increase fluid drag on the plunger and/or provide a motive force for the conveying at 145.

It is within the scope of the present disclosure that the transitioning at 135 may be performed and/or accomplished in any suitable manner. As an illustrative, non-exclusive example, and when the plunger includes the detector and the controller, the transitioning at 135 may be regulated and/or controlled by the controller, such as responsive to the detecting at 125. Under these conditions, the transitioning at 135 may be initiated by the controller automatically and/or without user intervention. However, it is also within the scope of the present disclosure that the transitioning at 135 may include transitioning responsive to receipt of a transition initiation signal by the controller. Such a transition initiation signal may originate within the surface region and/or from a user.

As another illustrative, non-exclusive example, the plunger may include a passive transition device. The passive transition device may be configured to passively transition the plunger from the low fluid drag state to the high fluid drag state responsive to the variable associated with the wellbore fluid stream transitioning from outside the threshold range to within the threshold range. Additionally or alternatively, the passive transition device also may be configured to passively transition the plunger from the high fluid drag state to the low fluid drag state responsive to the variable associated with the wellbore fluid stream transitioning from within the threshold range to outside the threshold range.

The transitioning at 135 may be accomplished in any suitable manner. As an illustrative, non-exclusive example, the transitioning at 135 may include increasing an outer diameter of the plunger. As another illustrative, non-exclusive example, the transitioning at 135 may include decreasing a cross-sectional area of an annular space that is defined by the plunger and a conduit body that defines the wellbore conduit. As yet another illustrative, non-exclusive example, and as illustrated in FIG. 11, the transitioning at 135 may include decreasing, or even eliminating, a cross-sectional area of flow-through opening 62 that is defined by, or within, the plunger.

It is within the scope of the present disclosure that the threshold range of the variable associated with the wellbore fluid stream may be defined in any suitable manner. As an illustrative, non-exclusive example, the variable associated with the wellbore fluid stream may include and/or be the pressure of the wellbore fluid stream. Under these conditions, the transitioning at 135 may include transitioning responsive to the pressure of the wellbore fluid stream exceeding a threshold maximum wellbore fluid stream pressure, responsive to a predetermined temporal pattern in the pressure of the wellbore fluid stream, responsive to a rate of change of the pressure of the wellbore fluid stream, and/or responsive to the rate of change of the pressure of the wellbore fluid stream being less than a threshold minimum rate of change of the pressure of the wellbore fluid stream.

As another illustrative, non-exclusive example, the variable associated with the wellbore fluid stream may include and/or be the temperature of the wellbore fluid stream. Under these conditions, the transitioning at 135 may include transitioning responsive to the temperature of the wellbore fluid stream being greater than a threshold maximum wellbore fluid stream temperature, responsive to a rate of change of the temperature of the wellbore fluid stream, and/or responsive to the rate of change of the temperature of the wellbore fluid stream being less than a threshold minimum rate of change of the temperature of the wellbore fluid stream.

As yet another illustrative, non-exclusive example, the variable associated with the wellbore fluid stream may include and/or be the flow rate of the wellbore fluid stream. Under these conditions, the transitioning at 135 may include transitioning responsive to the flow rate of the wellbore fluid stream being less than a threshold minimum flow rate of the wellbore fluid stream and/or responsive to a change (or decrease) in the flow rate of the wellbore fluid stream that is greater than a threshold rate of change (or decrease) in the flow rate of the wellbore fluid stream.

As another illustrative, non-exclusive example, the variable associated with the wellbore fluid stream may include and/or be the density of the wellbore fluid stream. Under these conditions, the transitioning at 135 may include transitioning responsive to the density of the wellbore fluid stream being greater than a threshold wellbore fluid stream density.

It is within the scope of the present disclosure that the transitioning at 135 may include transitioning responsive to a single variable associated with the wellbore fluid stream. Additionally or alternatively, it is also within the scope of the present disclosure that the transitioning at 135 may include transitioning responsive to a plurality of variables associated with the wellbore fluid stream (or that the variable associated with the wellbore fluid stream includes a plurality of variables associated with the wellbore fluid stream). This may include transitioning responsive to at least two, at least three, or more than three variables associated with the wellbore fluid stream being within respective threshold ranges. As a more specific but still illustrative, non-exclusive example, the transitioning at 135 may include transitioning responsive to the temperature of the wellbore fluid stream, the pressure of the wellbore fluid stream, and the density of the wellbore fluid stream all being within respective threshold ranges.

Releasing the supplemental material into the wellbore conduit at 140 may include releasing any suitable supplemental material into the wellbore conduit in any suitable manner. Illustrative, non-exclusive examples of the supplemental material are disclosed herein.

As an illustrative, non-exclusive example, the releasing at 140 may include releasing the supplemental material from the plunger while the plunger is within the target region of the wellbore conduit. As another illustrative, non-exclusive example, the releasing at 140 also may include releasing the supplemental material from the plunger while the plunger is being conveyed in the uphole direction within the wellbore conduit. As yet another illustrative, non-exclusive example, the releasing at 140 also may include releasing the supplemental material into an annular space that may be defined between the conduit body and the wellbore.

It is within the scope of the present disclosure that the releasing at 140 may be based upon and/or initiated responsive to any suitable criteria. As an illustrative, non-exclusive example, the releasing at 140 may be based, at least in part, on a value of the variable associated with the wellbore fluid stream. As another illustrative, non-exclusive example, the releasing may be initiated based upon, responsive to, concurrently with, and/or prior to the transitioning at 140 and/or the conveying at 145.

Conveying the plunger in the uphole direction within the wellbore conduit at 145 may include conveying the plunger in the uphole direction with, or within, the wellbore fluid stream to convey the liquid in the uphole direction. This may include providing a motive force for removal of the liquid from the wellbore conduit and/or producing the liquid from the wellbore conduit and/or from the gaseous hydrocarbon well and is illustrated in FIG. 5. It is within the scope of the present disclosure that the conveying at 145 further may include conveying one or more solid materials from the wellbore conduit and/or producing the one or more solid materials from the gaseous hydrocarbon well. Accordingly, references to conveying, producing, and/or otherwise removing liquid from the wellbore conduit may additionally include removing solids, which as discussed may be referred to collectively with the liquid as “wellbore material.”

As also discussed herein, it is within the scope of the present disclosure that the wellbore conduit may include and/or be a tapered wellbore conduit and/or that a cross-sectional shape and/or area of the wellbore conduit may vary along a length of the wellbore conduit. Under these conditions, methods 100 further may include selectively adjusting an outside diameter of the plunger, during the conveying, to correspond to a diameter of a portion of the wellbore conduit that includes the plunger.

It is also within the scope of the present disclosure that the plunger may be operated under conditions in which the flow of the wellbore fluid stream may be insufficient to convey the plunger in the uphole direction. Under these conditions, the plunger further may include a propulsion source that is configured to provide a motive force to convey the plunger in the uphole direction, and the conveying at 145 further may include actuating the propulsion source.

Determining the status of the plunger during the conveying at 150 may include determining any suitable property and/or status of the plunger during the conveying. As an illustrative, non-exclusive example, the determining at 150 may include determining a location of the plunger within the wellbore conduit, such as with the controller. As a more specific but still illustrative, non-exclusive example, the plunger may include a collar locator, and the determining may include counting tubing and/or casing collars with the collar locator as the plunger is conveyed there-past, comparing the counted collars to a collar log of collars that are present within the hydrocarbon well, and determining the location of the plunger based upon the comparison of the collar count to the collar log.

As another illustrative, non-exclusive example, the determining at 150 also may include determining a velocity of the plunger within the wellbore conduit, such as with the controller. As an illustrative, non-exclusive example, the plunger may include an accelerometer, and the determining at 150 may include determining the velocity based upon and/or utilizing the accelerometer. As another illustrative, non-exclusive example, the determining at 150 may include determining the velocity based upon, or utilizing the collar locator and/or the collar log.

As yet another illustrative, non-exclusive example, the determining at 150 may include determining an acceleration of the plunger with the accelerometer. As another illustrative, non-exclusive example, the plunger may include a gyroscope, and the determining at 150 may include determining a trajectory of the plunger within the wellbore conduit with the gyroscope.

Regulating the motion of the plunger at 155 may include regulating the motion of the plunger in any suitable manner. As an illustrative, non-exclusive example, the regulating at 155 may include regulating the velocity and/or velocity of the plunger within the wellbore conduit. This may include determining the velocity of the plunger with the controller, such as via the determining at 150, and subsequently regulating the velocity of the plunger with the controller, such as by controlling and/or regulating the fluid drag on the plunger within the wellbore conduit. This is illustrated in FIG. 16, where a size of flow-through opening 62 has been increased relative to that illustrated in FIGS. 14-15 to decrease the fluid drag on the plunger and decrease the velocity of the plunger in the uphole direction.

It is within the scope of the present disclosure that the regulating at 155 may include decreasing the velocity of the plunger in the uphole direction by any suitable amount, ceasing the motion of the plunger in the uphole direction, and/or even initiating motion of the plunger in the downhole direction. Additionally or alternatively, the regulating at 155 also may include increasing the velocity of the plunger in the uphole direction. This increasing and/or decreasing may be based upon real-time data that is collected by the plunger during the conveying at 145 and/or upon historical data that has been previously collected by the plunger.

As an illustrative, non-exclusive example, the regulating at 155 may include maintaining the velocity of the plunger below a threshold plunger speed. As another illustrative, non-exclusive example, the regulating at 155 may include increasing the fluid drag past the plunger within the wellbore conduit to increase the velocity of the plunger while the plunger is conveyed in the uphole direction. As yet another illustrative, non-exclusive example, the regulating at 155 also may include decreasing the fluid drag past the plunger within the wellbore conduit to decrease the velocity of the plunger while the plunger is conveyed in the uphole direction.

As another illustrative, non-exclusive example, the regulating at 155 also may include regulating a portion and/or fraction of a length of the wellbore conduit through which the plunger is conveyed during the conveying at 145. This may prevent contact between the plunger and a terminal end, such as at the surface region, of the wellbore conduit, thereby decreasing wear of and/or damage to the plunger and/or a remainder of the hydrocarbon well due to motion of the plunger within the wellbore conduit.

As an illustrative, non-exclusive example, the wellbore conduit may define a distance between the surface region and the target region of the wellbore conduit, as measured along the length of the wellbore conduit. The regulating at 155 may include calculating, during the conveying at 145, that a velocity of the wellbore fluid stream is sufficient to convey the liquid to the surface region and decreasing the fluid drag on the plunger to cease conveying the plunger in the uphole direction. This may permit the plunger to be returned to the target region of the wellbore conduit prior to the plunger traversing the entire distance between the surface region and the target region of the wellbore conduit and/or prior to the liquid being produced from the wellbore conduit. This is illustrated in FIG. 17 and discussed in more detail herein.

It is within the scope of the present disclosure that the plunger may traverse any suitable portion of the distance between the surface region and the target region of the wellbore conduit. As illustrative, non-exclusive examples, the plunger may traverse less than 100%, less than 95%, less than 90%, less than 85%, less than 80%, less than 70%, less than 60%, or less than 50% of the distance between the surface region and the target region of the wellbore conduit.

Collecting traverse data with the plunger at 160 may include collecting any suitable downhole data with the plunger during the conveying at 145. As illustrative, non-exclusive examples, the collecting at 160 may include collecting the pressure of the wellbore fluid stream as a function of location within the wellbore conduit, collecting the temperature of the wellbore fluid stream as a function of location within the wellbore conduit, collecting the flow rate of the wellbore fluid stream as a function of location within the wellbore conduit, and/or collecting the density of the wellbore fluid stream as a function of location within the wellbore conduit. Additionally or alternatively, the collecting at 160 also may include collecting a traverse survey of the wellbore conduit and/or generating a database of traverse data.

Producing the liquid from the gaseous hydrocarbon well at 165 may include producing the liquid in any suitable manner. This may include removing the liquid from the gaseous hydrocarbon well, such as via a surface tree 27, as illustrated in FIG. 8.

Adjusting the threshold range at 170 may include adjusting the threshold range in any suitable manner and/or based upon any suitable criteria. As illustrative, non-exclusive examples, the adjusting at 170 may include increasing a lower and/or an upper limit of the threshold range, decreasing the lower and/or upper limit of the threshold range, broadening the threshold range, and/or narrowing the threshold range. As additional illustrative, non-exclusive examples, the adjusting at 170 may include adjusting the threshold range based, at least in part, on previously collected downhole data and/or previously collected traverse data.

Repeating the methods at 175 may include repeating any suitable portion of methods 100. As an illustrative, non-exclusive example, and as illustrated in FIG. 17, the repeating at 175 may include returning the plunger to the target region of the wellbore conduit. As another illustrative, non-exclusive example, and subsequent to returning the plunger to the target region of the wellbore conduit, the repeating at 175 further may include repeating at least the flowing at 115, the maintaining at 120, the transitioning at 135, and the conveying at 145 to convey a respective volume of liquid from the wellbore conduit.

It is within the scope of the present disclosure that the repeating at 175 may include repeating without shutting in the hydrocarbon well and may be performed a plurality of times to remove a respective plurality of volumes of liquid from the wellbore conduit. Methods 100 may be repeated automatically, such as under the control of the controller.

When methods 100 include the repeating at 175, the collecting at 130 may include collecting downhole data when the plunger is maintained within the target region of the wellbore conduit and/or generating a database of downhole data as a function of time. Similarly, and when methods 100 include the repeating at 175, the collecting at 160 may include collecting traverse data when the plunger is being conveyed within the wellbore conduit and/or generating a database of traverse data as a function of time.

Referring more specifically to the process flow of FIGS. 13-18, FIG. 13 illustrates plunger 50 being maintained within target region 38 of wellbore conduit 36, such as during the maintaining at 120 of methods 100. As illustrated in FIG. 13, plunger 50 and/or a drag-regulating structure 60 thereof may be in low fluid drag state 64 and wellbore fluid stream 42 may flow past plunger 50 within wellbore conduit 36. As an illustrative, non-exclusive example, plunger 50 may define flow-through opening 62 and the wellbore fluid stream may flow through the flow-through opening.

While the wellbore fluid stream is flowing past the plunger, liquid 44 may collect within the wellbore conduit and/or on uphole side 56 of the plunger. When the variable associated with the wellbore fluid stream is within the threshold range, which indicates that removal of liquid 44 from the wellbore conduit would improve the flow of the wellbore fluid stream within the wellbore conduit, and/or which indicates that removal of liquid 44 from the wellbore conduit would be beneficial to the operation of the hydrocarbon well, and as illustrated in FIG. 11, plunger 50 and/or drag-regulating structure 60 thereof may be transitioned to high fluid drag state 66, such as during the transitioning at 135 of methods 100. This may include at least partially restricting, blocking, and/or occluding flow of the wellbore fluid stream through flow-through opening 62, as illustrated.

Transitioning plunger 50 to high fluid drag state 66 may increase a resistance to the flow of wellbore fluid stream 42 past the plunger, which may generate a motive (or pressure) force that may convey the plunger in uphole direction 80, as illustrated in FIG. 5 and discussed with reference to the conveying at 145 of methods 100. Motion of plunger 50 in the uphole direction also may convey liquid 44 in the uphole direction, as illustrated.

As discussed with reference to the determining at 150 of methods 100, the plunger may be configured to determine one or more status thereof while being conveyed in the uphole direction. In addition, and as discussed with reference to the regulating at 155 of methods 100, the plunger may be configured to regulate the motion thereof while being conveyed in the uphole direction. Thus, the plunger may be configured to selectively vary a resistance to fluid flow there-past while being conveyed in the uphole direction. This is illustrated in FIG. 16, in which flow-through opening 62 has been partially opened to decrease the resistance to fluid flow past the plunger relative to the high fluid drag state and slow and/or cease motion of the plunger in the uphole direction. This may be referred to herein as an intermediate state 69 for plunger 50. FIG. 16 illustrates plunger 50 transitioning to an intermediate state that defines a larger flow-through opening 62 when compared to high fluid drag state 66 and a smaller flow-through opening when compared to low fluid drag state 64. However, it is within the scope of the present disclosure that the motion of the plunger may be regulated in any suitable manner.

As an illustrative, non-exclusive example, and as discussed herein with reference to the regulating at 155, plunger 50 may determine that it is unnecessary to be conveyed the entire distance to the surface region and instead may transition to low fluid drag state 64 prior to reaching surface tree 27. This may permit the plunger to fall away from liquid 44 in downhole direction 82 back to target region 38 while liquid 44 continues to flow in uphole direction 80 and/or from the hydrocarbon well. This is illustrated in FIG. 17, with liquid 44 being separated from plunger 50. Flow of wellbore fluid stream 42 continues to convey liquid 44 in the uphole direction; however, plunger 50 is free to fall in the downhole direction and/or toward target region 38.

Alternatively, and as illustrated in FIG. 18, the plunger may continue to be conveyed in the uphole direction until reaching surface tree 27. Under these conditions, the plunger may be retained within surface tree 27 at least temporarily. This may permit the plunger to be charged and/or may permit data to be transferred from the plunger, as discussed herein with reference to the powering at 110.

FIGS. 19-30 provide more specific but still illustrative, non-exclusive examples of plungers 50 according to the present disclosure and/or of components of plungers 50, including plungers 50 of FIGS. 1 and 3-8. Any of the structures and/or features that are discussed herein with any one of FIGS. 9-20 may be included in and/or utilized with any other of FIGS. 9-20 without departing from the scope of the present disclosure. Similarly, any of the structures and/or features that are discussed herein with reference to any of FIGS. 9-20 may be included in and/or utilized with plungers 50 of FIGS. 1 and 3-8 without departing from the scope of the present disclosure.

FIGS. 19-20 are schematic representations of illustrative, non-exclusive examples of a plunger 50 according to the present disclosure located within a wellbore conduit 36. FIG. 19 illustrates plunger 50 in a low fluid drag state 64 and FIG. 10 illustrates plunger 50 in a high fluid drag state 66. Plunger 50 includes a drag-regulating structure 60 that is configured to regulate a fluid drag on the plunger when the plunger is located within wellbore conduit 36 and a wellbore fluid stream 42 flows past the plunger.

Plunger 50 also includes a controller 90. Controller 90 may be programmed to maintain drag-regulating structure 60 of plunger 50 in the low fluid drag state (as illustrated in FIG. 9) when a variable associated with the wellbore fluid stream is outside a threshold range. Controller 90 also may be programmed to selectively transition drag-regulating structure 60 of plunger 50 to high fluid drag state 66 (as illustrated in FIG. 20) responsive to the variable associated with the wellbore fluid stream being within the threshold range. As discussed in more detail herein, controller 90 further may be configured to adjust drag-regulating structure 60 to adjust the fluid drag on the plunger when the plunger is being conveyed within the wellbore. As an illustrative, non-exclusive example, plunger 50 and/or drag-regulating structure 60 thereof may at least partially define a flow-through opening 62, and drag-regulating structure 60 may be configured to transition to at least one intermediate state that is between low fluid drag state 64 and high fluid drag state 66 by changing the cross-sectional area of the flow-through opening.

As illustrated in FIGS. 19-20 at 67, flow-through opening 62 may be internal to and/or defined entirely by plunger 50. Additionally or alternatively, and as illustrated in FIGS. 9-10 at 68, flow-through opening 62 also may be defined between an external surface of plunger 50 and an internal surface of conduit body 34 and/or within an annular space that is defined between plunger 50 and conduit body 34.

Regardless of the exact configuration, and as discussed, drag-regulating structure 60 may be configured to selectively vary the cross-sectional area of flow-through opening 62 to selectively vary the resistance to flow of wellbore fluid stream 42 therethrough. This is illustrated in FIG. 20 by drag-regulating structure 60 at least partially blocking and/or occluding flow-through opening 62.

When flow-through opening 62 is defined between the external surface of plunger 50 and the internal surface of conduit body 34, the flow-through opening also may be referred to herein as an external flow-through opening 68. In such a configuration, drag-regulating structure 60 may be located within any suitable area and/or region along the external surface of plunger 50. Thus, and as illustrated in dashed lines, the drag-regulating structure may be located along a portion of a length of the external surface. Alternatively, and as illustrated in dash-dot lines in FIG. 10, the drag-regulating structure may be located along an entirety of the external surface.

When drag-regulating structure 60 is located along the external surface of plunger 50, the drag-regulating structure may include and/or be an expandable and/or a resilient drag-regulating structure 60 that may be configured to expand and/or contract to conform to a shape and/or diameter of wellbore conduit 36. This may permit the drag-regulating structure to maintain at least a threshold resistance to fluid flow past plunger 50 despite changes in the shape and/or diameter of wellbore conduit 36.

FIGS. 21-30 provide less schematic but still illustrative, non-exclusive examples of plungers 50 according to the present disclosure and/or of components thereof. More specifically, FIGS. 21-26 provide less schematic but still illustrative, non-exclusive examples of drag-regulating structures 60 according to the present disclosure that may be internal to and/or defined within plungers 50 according to the present disclosure. In contrast, FIGS. 28-30 provide less schematic but still illustrative, non-exclusive examples of a plunger 50 according to the present disclosure that includes a drag-regulating structure 60 that is at least partially external to and/or defined on an external surface of plunger 50 according to the present disclosure.

FIG. 21 is a schematic representation of an illustrative, non-exclusive example of a drag-regulating structure 60 according to the present disclosure in a low fluid drag state 64, while FIG. 22 is a schematic representation of the drag-regulating structure of FIG. 21 in a high fluid drag state 66. In FIGS. 21-22, drag-regulating structure 60 includes a fan 70, which may be rotated (as indicated in FIG. 22 at 71) to transition between low fluid drag state 64 and high fluid drag state 66, and it is within the scope of the present disclosure that fan 70 also may be rotated to one or more intermediate states between the low fluid drag state and the high fluid drag state to define one or more intermediate fluid drag states and/or to define different cross-sectional areas for a flow-through opening 62.

FIG. 23 is a schematic representation of an illustrative, non-exclusive example of a drag-regulating structure 60 according to the present disclosure in a low fluid drag state 64, while FIG. 24 is a schematic representation of the drag-regulating structure of FIG. 23 in a high fluid drag state 66. In FIGS. 23-24, drag-regulating structure 60 includes a valve 72, which may be rotated (as indicated in FIG. 24 at 71) to transition between low fluid drag state 64 and high fluid drag state 66, and it is within the scope of the present disclosure that valve 72 also may be rotated to one or more intermediate states between the low fluid drag state and the high fluid drag state to define one or more intermediate fluid drag states and/or to define different cross-sectional areas for a flow-through opening 62.

FIG. 25 is a schematic representation of an illustrative, non-exclusive example of a drag-regulating structure 60 according to the present disclosure in a low fluid drag state 64, while FIG. 26 is a schematic representation of the drag-regulating structure of FIG. 25 in a high fluid drag state 66. In FIGS. 25-26, drag-regulating structure 60 includes a choke plate 74, which may be rotated (as indicated in FIG. 26 at 71) to transition between low fluid drag state 64 and high fluid drag state 66, and it is within the scope of the present disclosure that choke plate 74 also may be rotated to one or more intermediate states between the low fluid drag state and the high fluid drag state to define one or more intermediate fluid drag states and/or to define different cross-sectional areas for a flow-through opening 62.

FIG. 27 is a schematic side view of illustrative, non-exclusive examples of a plunger 50 according to the present disclosure in a low fluid drag state 64 and located within a wellbore conduit 36, while FIG. 28 is a schematic top view of the plunger of FIG. 27. FIG. 29 is a schematic side view the plunger of FIG. 27 in a high fluid drag state 66, while FIG. 30 is a schematic top view of the plunger of FIG. 29. In FIGS. 27-28, plunger 50 and conduit body 34 together define a flow-through opening 62 within an annular space therebetween. In addition, drag-regulating structure 60 is an expanding structure 76 that may be adjusted to vary the cross-sectional area of flow-through opening 62.

As an illustrative, non-exclusive example, drag-regulating structure 60 may include and/or be a cone 78 and screw 79 assembly. Under these conditions, screw 79 may be drawn toward a remainder of plunger 50, thereby expanding cone 78 and decreasing the cross-sectional area of flow-through opening 62, as illustrated in FIGS. 29-30. Conversely, and as illustrated in FIGS. 27-28, screw 79 may be extended away from a remainder of plunger 50, thereby permitting cone 78 to retract and increasing the cross-sectional area of flow-through opening 62.

INDUSTRIAL APPLICABILITY

The systems and methods disclosed herein are applicable to the oil and gas industries.

It is believed that the disclosure set forth above encompasses multiple distinct inventions with independent utility. While each of these inventions has been disclosed in its preferred form, the specific embodiments thereof as disclosed and illustrated herein are not to be considered in a limiting sense as numerous variations are possible. The subject matter of the inventions includes all novel and non-obvious combinations and subcombinations of the various elements, features, functions and/or properties disclosed herein. Similarly, where the claims recite “a” or “a first” element or the equivalent thereof, such claims should be understood to include incorporation of one or more such elements, neither requiring nor excluding two or more such elements.

It is believed that the following claims particularly point out certain combinations and subcombinations that are directed to one of the disclosed inventions and are novel and non-obvious. Inventions embodied in other combinations and subcombinations of features, functions, elements and/or properties may be claimed through amendment of the present claims or presentation of new claims in this or a related application. Such amended or new claims, whether they are directed to a different invention or directed to the same invention, whether different, broader, narrower, or equal in scope to the original claims, are also regarded as included within the subject matter of the inventions of the present disclosure.

While the presently disclosed technology may be susceptible to various modifications and alternative forms, the exemplary embodiments discussed above have been shown only by way of example. However, it should be understood that the invention is not intended to be limited to the particular embodiments disclosed herein. Indeed, the presently disclosed inventions include all alternatives, modifications, and equivalents falling within the true spirit and scope of the invention as defined by the following appended claims. 

What is claimed is:
 1. A plunger apparatus, comprising: a plunger body having a substantially annular cross-section and an outer diameter, wherein the outer diameter is less than an inner diameter of a tubular string of a gas producing well, the plunger body able to travel within the tubular string; a flow channel through the plunger body; an actuatable external seal assembly operatively provided on or within an outer surface of the plunger body, the actuatable external seal assembly having a deployed position and a retracted position; and a plug mechanism mechanically integrated with the plunger body and reversibly moveable between a closed position and an open position with respect to the plunger body and flow channel, the open position configured to permit the passage of a continuous water slug past the plug mechanism and through the flow channel; wherein the plug mechanism operatively extends from an end of the plunger body and comprises a substantially streamlined profile when the plug mechanism is operatively extended in the open position with respect to the plunger body and flow channel; and wherein the actuatable external seal assembly is actuated by the plug mechanism between the deployed position when the plug mechanism is operatively in the closed position and the retracted position when the plug mechanism is operatively in the open position.
 2. The apparatus of claim 1, wherein the plunger apparatus is configured to fall through the fluid in the wellbore tubular when the plug mechanism is in the open position and the actuatable seal assembly is in the retracted position at a falling velocity relative to the continuous water slug velocity greater than about (150+50×M) feet per minute (ft/min), where M is the mass in units of lbm of the plunger apparatus.
 3. The apparatus of claim 1, further comprising an actuation member operatively engaged with the plug mechanism and having a surface area exposed to the continuous water in the gas producing well smaller than a surface area of the plug mechanism exposed to the continuous water in the gas producing well and the surface area exposed to the fluid flow having a streamlined profile, wherein the plunger apparatus falls in the open position until the actuation member encounters an actuation force causing (i) the plug mechanism to move to the closed position and (ii) the actuatable external seal assembly to move from the retracted position to the deployed position.
 4. The apparatus of claim 1, wherein the actuatable external seal assembly comprises at least two seals and the plug mechanism selectively actuates one of the seals without actuating the other of the at least two seals.
 5. The apparatus of claim 4, wherein thereafter, the plug mechanism selectively actuates the other of the seals without actuating the one of the seals.
 6. The apparatus of claim 4, wherein thereafter, the plug mechanism actuates the other of the at least two seals.
 7. The apparatus of claim 4, further comprising a seal selector mechanism to cause the plug mechanism to selectively actuate at least one of a determined one of the at least two seals, a determined other of the at least two seals, and a determined both of the at least two seals.
 8. The apparatus of claim 7 wherein the seal selector mechanism operates at least one of mechanically, hydraulically, pneumatically, electronically, and combinations thereof
 9. The apparatus of claim 2, further comprising a locking device configured to hold the plug mechanism in the open position as the plunger apparatus falls through continuous water at the falling velocity.
 10. The apparatus of claim 1, further comprising a friction reduced coating on at least a portion of the plunger apparatuses, wherein the FRC is selected from the group consisting of: diamond-like carbon (DLC), advanced ceramics, graphite, and near-frictionless carbon (NFC).
 11. The apparatus of claim 1, wherein the plunger is a one-piece plunger.
 12. A two-piece plunger apparatus, comprising: a plunger body having a substantially annular cross-section and an outer diameter, wherein the outer diameter is less than an inner diameter of a tubular string of a gas producing wellbore and the plunger body is able to travel within the tubular string; a flow channel through the plunger body; a plug mechanism releasably connectable with the plunger body, the plug having a closed (connected) position with respect to the plunger body and an open (released) position with respect to the plunger body and the flow channel, the open position configured to permit the passage of continuous fluid flow through the flow channel while maintaining the open position; and an actuatable external seal assembly operatively provided on or within an outer surface of the plunger body, the actuatable external seal assembly having a deployed position and a retracted position; and wherein the actuatable external seal assembly is actuated between (i) the deployed position when the plug mechanism is releasably connected to the plunger body in the closed position and (ii) the retracted position respectively when the plug mechanism is disengaged from the plunger body.
 13. The apparatus of claim 12, wherein the plunger body and flow channel comprise a profile, wherein at least a portion of the profile is selected from the group consisting of: a substantially streamlined profile, a substantially tapered profile, and any combination thereof
 14. The apparatus of claim 13, wherein when the actuatable external seal assembly is in the retracted position the plunger body is configured to fall through continuous fluids flow in the tubular string at a falling velocity relative to the continuous fluid flow at a falling velocity greater than about (150+50×M) feet per minute (ft/min), where M is either the mass in units of lbm of the plunger body or the mass in units of lbm of the plug mechanism.
 15. The apparatus of claim 12, wherein the actuatable external seal assembly comprises at least two seals and the plug mechanism selectively actuates one of the seals without actuating the other of the at least two seals.
 16. The apparatus of claim 15, wherein thereafter, the plug mechanism selectively actuates the other of the seals without actuating the one of the seals.
 17. The apparatus of claim 15, wherein thereafter, the plug mechanism additionally actuates the other of the at least two seals.
 18. The apparatus of claim 15, further comprising a seal selector mechanism to cause the plug mechanism to selectively actuate either a determined one of the at least two seals, a determined other of the at least two seals, and a determined both of the at least two seals.
 19. The apparatus of claim 18, wherein the seal selector mechanism operates at least one of mechanically, hydraulically, pneumatically, electronically, and combinations thereof
 20. The apparatus of claim 19, further comprising a controller, wherein a position of the plug mechanism is at least one of input into the processor and determined by the processor, and wherein the processor controls the seal selector mechanism.
 21. The apparatus of claim 20, wherein the external seal assembly is actuated between the deployed position and the retracted position by the controller by at least one of fluidic inflation and deflation of the external seal assembly.
 22. The apparatus of claim 20, wherein the seal selector mechanism further comprises a control valve assembly controlled by the controller, the control valve assembly selectively controlling actuation of a selected portion of the actuatable external seal assembly to the deployed position and concurrent actuation of other portions of the actuatable external seal assembly in the retracted position.
 23. The apparatus of claims 12 further comprising a friction reduced coating on at least a portion of the plunger apparatuses, wherein the FRC is selected from the group consisting of: diamond-like carbon (DLC), advanced ceramics, graphite, and near-frictionless carbon (NFC).
 24. A method of producing hydrocarbon-containing gas, comprising: providing a hydrocarbon well having a wellbore, a flow line in fluid communication with the wellbore, a top portion with a tubular head stopper, and a bottom portion with a bottom bumper stopper; producing a volume of liquids and a gaseous stream imparting a gaseous pressure from the bottom portion to the top portion of the wellbore, wherein at least a portion of the produced volume of liquids remains in the bottom portion of the wellbore; and operating a plunger apparatus in the wellbore in a plunger lift cycle, the lift cycle comprising: lifting at least a portion of the produced volume of liquids in the bottom portion of the wellbore towards the top portion of the wellbore and within the flow line utilizing the gaseous pressure from the bottom portion to the top portion of the wellbore, wherein the plug mechanism of the plunger apparatus comprises; (i) a plunger body having a substantially annular cross-section and an outer diameter, wherein the outer diameter is less than an inner diameter of a tubular string of a gas producing well, the plunger body able to travel within the tubular string; (ii) a flow channel through the plunger body; (iii) an actuatable external seal assembly operatively provided on or within an outer surface of the plunger body, the actuatable external seal assembly having a deployed position and a retracted position; and (iv) a plug mechanism mechanically integrated with the plunger body and reversibly moveable between a closed position and an open position with respect to the plunger body and flow channel, the open position configured to permit the passage of a continuous water slug past the plug mechanism and through the flow channel; (v) wherein the plug mechanism operatively extends from an end of the plunger body and comprises a substantially streamlined profile when the plug mechanism is operatively extended in the open position with respect to the plunger body and flow channel; and (vi) wherein the actuatable external seal assembly is actuated by the plug mechanism between the deployed position when the plug mechanism is operatively in the closed position and the retracted position when the plug mechanism is operatively in the open position impacting the tubular head stopper with the plunger apparatus causing the plunger apparatus to change the operating state from the closed position to an open position with respect to the plunger body and flow channel, and causing the actuatable external seal assembly to operatively change from the deployed position to the retracted position; descending the automatic plunger apparatus in the open position to the bottom of the wellbore, wherein a gravitational force on the plunger apparatus is greater than a combined drag force and pressure force on the plunger apparatus caused by the passage of the volume of fluids and the gaseous stream; impacting the bottom bumper stopper with the plunger apparatus causing the plunger apparatus to automatically change the operating state from the open position to the closed position and actuate the external seal assembly from the retracted position to the deployed position, and repeating the plunger lift cycle.
 25. The method of claim 24, wherein the plunger apparatus includes a plug mechanism and a plunger body, wherein the plug mechanism extends from the plunger body towards the bottom portion of the wellbore in the open position and comprises a substantially streamlined shape configured to fall through continuous water in the hydrocarbon well while maintaining the open position.
 26. The method of claim 25, wherein the plunger apparatus is configured to fall through continuous water in the gas producing well at a falling velocity relative to the continuous water velocity greater than about (150+50×M) feet per minute (ft/min), where M is the mass in units of lbm of the plunger body.
 27. The method of claim 24, further comprising controlling the plunger lift cycle, comprising: catching the plunger apparatus at or near the top portion of the wellbore; holding the plunger apparatus for a period of time; and releasing the plunger apparatus upon the occurrence of a condition in the wellbore.
 28. The method of claim 24, further comprising: forming the plunger body out of a single piece of material; fixedly attaching a support element to the plunger body within the flow channel; and slidably attaching a valve element to the support element.
 29. The method of claim 24, further comprising applying a friction reduced coating on at least a portion of the plunger, wherein the FRC is selected from the group consisting of: diamond-like carbon (DLC), advanced ceramics, graphite, and near-frictionless carbon (NFC). 